Ops & WSG Manual

technical training 2008

Operations & Wellsite Geologist Stag Geological Services Ltd. Reading United Kingdom

Revision E January 2008 www.stag-geological.com


Section 1

Operations & Wellsite Geology Chapter 1: Operations Geology Chapter 2: Wellsite Geologist Chapter 3: Wireline Logs Chapter 4: Coring Chapter 5: Log Witnessing Chapter 6: Pressure Concepts Chapter 7: Pressure Detection Chapter 8: Fracture Pressure

Section 2

Reporting Procedures End-of-Well Report Daily Reports

Section 3

Wellsite Geological Processes Chapter 1: Formation Evaluation Chapter 2: Lag Time Chapter 3: Mudlogging Unit Chapter 4: Gas Detection Chapter 5: Sedimentary Petrology Chapter 6: Cuttings Evaluation

Section 4

Measurement While Drilling Chapter 1: MWD Overview Chapter 2: Imaging Logs Chapter 3: Geosteering Techniques Chapter 4: Geosteering Strategies

Section 5

Log Examples

Section 6

Geosteering Case Study

Section 7

Log Interpretation Charts

Figure 1: Table of Contents

Operations Geology Introduction Operations and Wellsite Geology support plays a crucial role in the success of drilling and production ventures. Typically the Operations Geologist will be a member of the exploration department of the operating company although now, in many cases, he is responsible to the project or drilling manager and thus may have a dual reporting role. The drilling department will require information during the planning stage regarding the detailed geological stratigraphy, targets, offsets, problem formations and the exploration department will require the collection and quality control of geological data as the well is drilled. The Operations Geologist will have been assigned at the beginning of the well planning phase and is the main communication link between the exploration and drilling departments. He is a vital interface between the rig and the office and is also responsible for the provision of wellsite contractor services. Partners will require the Operations Geologist to provide them with data and operational information in a timely manner. The Wellsite Geologist is responsible the wellsite geological data collection and quality control of contractor’s services under the supervision of the Operations Geologist. He may not have been involved in the planning process but obviously needs to be sufficiently briefed prior to the commencement of the job in order to be fully aware of the duties and responsibilities required of him. The Operations Geologist and the Wellsite Geologist may be full time employees of the Operator or specialist consultants. Consultants are usually very experienced in both drilling and formation evaluation; many having begun their careers as Mudloggers and so gained an appreciation of many the different disciplines involved in drilling, evaluating and completing wells. It is often the case that full time employees of oil companies are given operations and wellsite roles early in their careers as a stepping stone in their overall development. The latter will need a great deal of supervision, guidance and training from their managers as well as constructive support form the contractor’s personnel that they are dealing with.

General Duties of the Operations Geologist • Be an active member of the project team providing geotechnical support to design and execute a well plan to meet exploration objectives • Provide a Data Acquisition program to meet licence members objectives and government requirements

Operations & Wellsite Geology

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Operations Geology • Compile the G&G section of the drilling program. • Identify and select wellsite and post well analysis services • Manage and QA formation evaluation Contractors and services • Provide office based technical support to the rig team • Receipt of data from all formation evaluation service providers • Logistical support for wellsite Formation evaluation services • Focal point for distribution of daily updates and communication for partners and government bodies • Review of actual versus planned performance indicators • Cost control of formation evaluation services • Compilation of Completion Log • Production of End-of-Well report

Well Planning Establishing a time frame for all activities is critical to the success of the project management. All critical path activities should be carried out efficiently and smoothly; other activities need to be conducted in a manner that will not adversely affect critical path activities and particularly to the effect that they will not become critical path activities themselves. The lack of key geological information can have a serious impact on the critical path. For example the lack of site survey information may delay rig choice and well path planning and the lack of a pore pressure profile will impact casing and wellhead design.

Tasks for the Operations Geologist • Co-ordinate the needs of the exploration team and compile a DAP • Organise vendor presentations for the project team • Undertake vendor appraisals and organise contracts • Meet deadlines for the Detailed Drilling Plan: Pore Pressure/Fracture Pressure Profiles, Site Survey data, Geological hazards • Prepare a Data Acquisition Procedures manual • Attend partner and government agency meetings • Organise and facilitate pre-spud meetings and training

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Operations Geology Well Planning Process

Well Planning Process Asset Team Requirements

Wellobjectives objectives Well

Increase production & reserves Increase production & reserves Increase efficiency & decrease project development cost Increase efficiency & decrease project development cost Flexible design: producer & injector Flexible design: producer & injector Improve Enhanced Oil Recovery/water-flood Improve Enhanced Oil Recovery/water-flood Exploration tool in reservoir evaluation Exploration tool in reservoir evaluation Any combination of the above Any combination of the above

Geology Geophysics

Fluid Fluid Properties oil, water, gas ! API Gravity, Viscosity ! PVT Data !

Archives !Field

!Petrophysicss !Engineering !Simulation !Special

DataAcquisition Acquisition Data Analysis &&Analysis

Petrophysics (Logs)

!

Gross column ! Net column

WellProposal Proposal Well

!

© 1999 Stag Engineering Services Limited

! !

Φ

Petrology Mineralogy Clay Content

Productivity/injectivity

Lithology Fluid Saturation !Geological Markers

(inc. Reservoir Deliverables) (inc. Reservoir Deliverables)

Studies

Petrophysics (Cores) ! Φ & Horiz. & vert. k.

!

Surface location & ID, well length, orientation & targets Surface location & ID, well length, orientation & targets Correlation wells, regional data, sections & maps Correlation wells, regional data, sections & maps Prognosed Geology, formation tops, FBG, temperature Prognosed Geology, formation tops, FBG, temperature Formation evaluation, logging, coring WSG Formation evaluation, logging, coring WSG Expected reservoir pressures & fluids Expected reservoir pressures & fluids Recoverable reserves, production forecast oil, water & gas Recoverable reserves, production forecast oil, water & gas Completion requirements inc. sand control &/or stimulation Completion requirements inc. sand control &/or stimulation Completion design & predicted flowing conditions Completion design & predicted flowing conditions Potential for for future well interventions Potential for for future well interventions Quality indicators Quality indicators

Studies

!Geology

Seismic Sections ! Maps ! Structures !

Well location Drilling & completion details ! Well treatment ! Well type producer, injector, Obs. ! Status Shut In, Abd, Prod, etc ! Artificial Lift System ! Rates, oil, water, gas, choke size ! Cumulative oil, water, gas

!

!

!

!

Reserves Field Block ! Area of Interest ! Reservoir ! Well ! !

ReservoirAnalysis Analysis Reservoir

- Original oil/gas in place & recovery to date - Original oil/gas in place & recovery to date - Drive mechanisms - Drive mechanisms - Changes of OWC & GOC with time - Changes of OWC & GOC with time - Rock & fluid characteristics of all zones - Rock & fluid characteristics of all zones - Production/completion problems e.g. sand, wax - Production/completion problems e.g. sand, wax - Depletion of reservoir pressure with time - Depletion of reservoir pressure with time - Production forecasts assuming no EOR - Production forecasts assuming no EOR - Field/reservoir recovery factors - Field/reservoir recovery factors - Remaining recoverable oil & gas reserves - Remaining recoverable oil & gas reserves - Identify/explain zones of low recovery &/or bypassed oil - Identify/explain zones of low recovery &/or bypassed oil - Construct reservoir model to predict reservoir performance - Construct reservoir model to predict reservoir performance

Methods Methods

Material balance calculations Material balance calculations Volumetric analysis Volumetric analysis Decline curve analysis Decline curve analysis Log evaluation Log evaluation Pressure transient analysis Pressure transient analysis Analytic models e.g. JTI Horizontal Analytic models e.g. JTI Horizontal EOR screening EOR screening Geostatistics & reservoir characterization Geostatistics & reservoir characterization Reservoir simulation Reservoir simulation

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Figure 1: Well Planning Process The project team will have determined a set of well objectives which will form the basis of the Detailed Drilling Plan (DDP). This will be compiled from G&G data supplied by the Operations and Exploration department. In turn the DDP will allow the Authorisation for Expenditure (AFE) proposal to be written and submitted for approval. The AFE then becomes the most important document in the planning and execution phases since it provides the controls and limitations for the entire project.


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Operations Geology

Figure 2: Detailed Drilling Plan

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Operations Geology

Figure 3: AFE Template


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Operations Geology Generalised G&G data needs to be submitted to the Drilling Engineers at an early stage in order that the initial well plan and design can begin. This may be up to one year before spud date. The G&G data will necessarily be lacking detail but the generalities of a planned logging programme will influence the drilling plan. Some logging tools will, for example, be mud specific and will need to be identified early on. The Geological Program and the DDP will evolve over time. They will be compiled by individuals with input from many other contributors. Regular meetings need to be held with project and exploration team members to communicate goals and plans and solicit constructive feedback. All planning documents need to be verified by team members before being submitted for approval. The distribution of all documents will be controlled in order that amendments may be managed correctly and that all individuals are using the most up-to-date versions of them.

Summary of Operations Geological Issues for Well Planning Well Objectives • Should take into account all of the above points and will include production criteria, reservoir exposure, coring, testing and safety issues. • Risks- Mitigations • MWD/LWD • “Wireline” logs • Other formation evaluation services • Communications & Team Work

Critical G&G data for Detailed Drilling Plan The following data is critical for the early development of the detailed drilling plan. They impact rig selection, casing and wellhead equipment selection. • Site Survey/Shallow hazards • Pore Pressure Prognosis • Fracture Pressure Prognosis • Geological Hazards

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Operations Geology Site Survey/Shallow hazards The site survey should be carried out at least six months prior to spud and will normally consist of the following components: • Positioning • Sea-Bed Investigations • Sub-Bottom Investigations

GPS Differential Corrections

Seismic Relection (sub-surface)

Sidescan Sonar (surface area)

Figure 4: Components of a Site Survey


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Operations Geology Positioning Geodesy: Measuring the Earth 3 Reference Surfaces: • Topography • Geoid • Ellipsoid (Spheroid) 2 Measurement Systems: • Geographical • Projections Ellipsoid is the basic reference surface Heights are often related to Geoid (MSL) GPS heights are related to Ellipsoid Latitude/ Longitude referenced to Ellipsoid Lat/ Long ALWAYS need associated DATUM Projections (UTM etc.) ALSO need DATUM

Locating & Orientating the Ellipsoid in space requires 8 constants to be defined: • Size & shape of Ellipsoid (2 parameters) • Direction of minor axis (2 parameters) • Position of the centre (3 parameters) • A zero coordinate (1 parameter) • Naming of Datums can be problematical Venezuela has 17 Datums in Maracaibo 3 are called "Maracaibo Cathedral”

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Operations Geology Ellipsoids always associated with Datums • Ellipsoid names can be duplicated • Ellipsoid PARAMETERS are best • There are several “versions” of ED50 Datum • All convert to/from WGS 84 DIFFERENTLY • 54 deg N/ 3 deg E (ED50 / ED87 Equivalent): --53d 59m 57.51s N/ 2d 59m 55.08s E (WGS 84) • 54 deg N/ 3 deg E (ED50, old “general”): --53d 59m 57.29s N/ 2d 59m 54.87s E (WGS 84) • Approx. 8 metres variation • Vessel navigation, typically (95%) 3 - 5 m • Bathymetry: depends on depth • Sidescan sonar, typically (95%, relative) 5 - 8 m • Sparker, boomer, airgun (95%, relative)3 - 5 m • Hydrophone arrays (95%, relative) 5 - 8 m • RMS Sidescan6 - 9.5 m • RMS sources4 - 7 m • RMS hydrophones

Sea-bed Investigations Sea floor cores and samples are taken to determine the nature and strength of sediments and to calibrate side-scan sonar and bathymetry data. This is particularly important for Jack-Up rigs in order to prevent leg instability.

Sea-floor samples Grab sampler This is dropped under its own weight and is spring triggered on impact. The bucket rotates, trapping the sample. It is limited to the top 30-40 cm of seabed. The sample is collected with minimal disturbance.


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Operations Geology

Grab & Core Sampling Required to “ground truth” sidescan and bathymetry data by calibrating records to sample types. Samples taken at points in the survey area identified by sidescan. Enables confident extrapolation of very shallow sediments over a wide area

Free-Fall Release Gear Weight

Rotating Bucket

Fin

Weight Core Tube Piston Coil Spring

Core Liner

Grab sampler dropped under own weight. Spring triggered on impact. Bucket rotates, trapping sample. Limited to top 30-40 cm of seabed. Sample collected with minimal disturbance.

Weight

Tough Nose & Core Catcher

Figure 5: Grab & Core sampling

Core sampler Gravity Corers - these corers are available in a wide range of options, with lengths of corer tubes from 1m to 10m in a variety of diameters, with or without internal tube liners. With tube barrels of either mild steel (with a choice of finishes) or stainless steel. The tube barrels are supplied with or without cutters. The largest Gravity Corer supplied to-date, had a barrel length of 32m and weight 10 tonnes.

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Operations Geology

Figure 6: Grab & Core sampling

Side-scan Sonar The intensity of sound received by the sidescan-sonar tow vehicle from the sea floor (backscatter) provides information as to the general distribution & characteristics of the superficial sediment. This may include channels, boulders, subsidence (pock marks), sea-bed features and sub-sea structures e.g. wellheads, pipe lines and shipwrecks. In the lower left schematic, strong reflections (high backscatter) from boulders, gravel & vertical features facing the sonar transducers are white; weak reflections (low backscatter) from finer sediments or shadows behind positive topographic features are black. The sea floor is typically surveyed in swaths 100-500 meters wide; the swaths are mosaiced together to form a composite image of the survey area.


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Operations Geology

Figure 7: Sidescan sonar

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Operations Geology

Sidescan Example: Port Hunter

Figure 8: Sidescan Sonar example


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Operations Geology

Figure 9: Pockmarks

Seismic Reflection Profiling Seismic reflection profiling is accomplished by towing a sound source that emits acoustic energy at intervals behind a survey vessel. The transmitted acoustic energy is reflected from boundaries between various mediums of different acoustic impedances (i.e. the water-sediment interface or between geologic units). Acoustic impedance is defined by the bulk density of the medium & the velocity of the sound within that medium. The reflected acoustic signal is received by a shiptowed hydrophone (or array of hydrophones), which converts the reflected signal to a digital or analog signal. The signal from the hydrophone can be logged, filtered & displayed. The digital data can then be gathered with information from adjacent hydrophones to enhance the signal to noise ratio. A shallow seismic survey is commonly run over 6.5 square km area with the spud location at its centre. It will identify shallow geological features such as channels, shallow sands and shallow gas deposits down to the depth at which casing would normally be set at the BOP installed.

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Operations Geology

Figure 10: Seismic Reflection Profiling The Sparker The Sparker is a relatively high powered sound source, dependent on an electrical arc which momentarily vaporises water between positive & negative leads. The collapsing bubbles produce a broad band (50 Hz - 4 kHz) omni directional pulse which can penetrate several hundred meters into the subsurface. Resolution is 2-5 metres. Hydrophone arrays towed nearby receive the return signals.


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Operations Geology

Figure 11: Sparker

The Pinger (CHIRP) The Geo Acoustics GeoChirp is a sub-bottom profiling system for high resolution shallow geophysical surveys. The Chirp concept uses advanced frequency modulation (FM) & digital signal processing to attain good penetration of the subbottom layers whilst achieving higher resolution records. The Geochirp is configured with the electronics bottle mounted on the towfish & the receiving hydrophone attached & towed directly from the rear of the fish. Data from the GeoChirp may be displayed on a variety of graphics recorders or sonar acquisition systems.

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Operations Geology

Figure 12: Pinger


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Operations Geology

Figure 13: Boomer

Figure 14: Sparker Profile

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Operations Geology

Figure 15: Pinger Profile


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Operations Geology

Figure 16: Boomer Profile

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Operations Geology

Figure 17: Pinger - Shallow Gas profile

Figure 18: Shallow Gas profile


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Operations Geology The Boomer This is a broad band sound source operating in the 300Hz - 3kHz range. By sending electrical energy from the power supply through the wire coils (above), the two spring loaded plates in the boomer transducer are charged, causing the plates to repel, thus generating an acoustic pulse. This system is commonly mounted on a sled & towed behind the boat. Resolution of the boomer system ranges from 0.5 to 1 m; penetration from 25 to 50 m. The processed section, (Fig.18), is of a boomer source into a single short streamer. Profile spacing 500m. Sea floor is either a strong till-layer reflection (1) or a weaker mud horizon at (2) from unconsolidated sediments. A bright spot at 3 is a reflection with inverted signal phase. This has been interpreted to be shallow gas, at a depth of around 4 m below the mud surface. There is a second till-layer at (4) which is faulted & may consist of coarser material than the sea floor till. At this depth we also see dipping features (5) which aren’t classified. Deeper, we start to see prominent multiples, which mask deeper geology.

Overview Of Shallow Gas Offshore v onshore risks Shallow gas has often been thought of as a problem that occurs only offshore - this is not true (although shallow gas onshore is less frequent). The guidelines laid out in this guideline document are to be applied (where necessary) to all operations irrespective of whether on land or offshore. It is not common practice to conduct shallow gas surveys onshore.

Definition ‘Shallow Gas’ can be defined as formation gas that is encountered in a well prior to running the full pressure containing BOP stack. In general, this means ‘top hole’ until 20" casing (or similar diameter) has been set, but wells have been drilled with a diverted installed until the 133/8" casing has been set at depths in excess of 4,000 ft.

Equipment The equipment employed to handle shallow gas is principally dependent on the type of installation or rig carrying out the drilling operation. If the installation is a floating unit, then where environmental legislation permits the well should be drilled riserless. Where riserless drilling is not permitted a subsurface divertor is

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Operations Geology employed. Both options allow all gas to be released subsea & the rig involved to move off the location. If a bottom supported rig is being employed a surface divertor system is used. In case the rig cannot be moved off location, diverting the gas away from the unit is the only option. Shallow gas is only diverted if the wellbore formation is sufficiently weak that if closed-in by use of a conventional BOP stack a sub-sea blowout would result.

Type of Gas Shallow Gas is most likely to be a hydrocarbon gas but may also be H2S. It can be capable of carrying large quantities of abrasive formation such as sand & rocks, consequently erosion of equipment is a major issue. Irrespective of its chemistry, shallow gas will create a risk to personnel & equipment if allowed to surface around the rig.

Origins of Shallow Gas Gas is generally believed to be the result of decayed organic material & as such can exist at any depth. Accumulations that can endanger the drilling operation during top hole, are most likely to be in sediments with high porosity & high permeability. Shallow gas accumulations may be under either a ‘normal’ or ‘abnormal’ pressure regime. An accumulation of shallow gas can therefore exist in varying quantities (volume), under varying pressures & in formations with different permeabilities. No matter what the conditions, shallow gas must ALWAYS be treated with extreme care. On multi-well platforms, gas may accumulate at shallow depths as a result of communication behind poorly cemented casing strings. H2S can also be a major problem due to decomposing mud products.

Detection The detection of shallow gas falls into two distinct phases: Prior to spud This involves various surveys that are carried out by the Operator prior to drilling. These include, but are not limited to: a) Sea bed surveys b) Shallow seismic surveys


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Operations Geology c) Soil borings Soil sampling is a hazardous operation, because shallow gas might be encountered during the coring process. The lack of string valve protection, can result in the hole blowing out through the pipe. In offshore operations, a safer approach would be to investigate the soil for shallow gas prior to undertaking soil sampling by drilling a test hole with float valve protection to at least the deepest sampling point. It is imperative that the Operator undertakes extensive soil borings when selecting a location for a bottom supported rig &/or platform location. Soil borings offer: • Tie-in of geology to seismics & other offset data. • Potential shallow gas zones. • Information on hydrocarbon content. • Detailed lithology of soil layers. • Strength determination of formation, important for platform position, conductor setting depth & the cementation design for surface casing. Note that in soft seabed areas, leg penetration can be up to 100 ft below the mud line, which can cause risks with jacking up. d) Pilot hole drilling from specialised units Pilot holes may be drilled up to conductor string depth, as part of a preliminary shallow gas investigation programme, prior to spudding a well. The following situations may justify drilling pre-spud pilot holes: • At locations where offshore platforms are planned to be installed. • In areas where little geological information is available. • In areas with a high probability of shallow gas whereby the depth of shallow gas is unknown. • In floating drilling operations, which require returns to surface for geological reasons (formation cuttings control). • Pilot hole drilling (pre-spud) should be done with a floating vessel, which can move off location efficiently in case of a shallow gas problem. e) Information which may be used to examine the potential for shallow gas should also include a review of all existing documentation (& experience) for the area in question, which may contain useful pointers to shallow gas. The following reports may be considered: • Subsea Platform Inspection Reports • Pile & Conductor Reports

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Operations Geology • Offset Well Data Whatever type of data is collected, it is the responsibility of the Rig Manager to ensure that data is reviewed & analysed in conjunction with the client. It is essential that offshore & onshore senior personnel make every effort to research & communicate information relating to special features during top hole drilling. Remember that the success of a survey (non-invasive technique), is no guarantee that there will be an absence of shallow gas. Specific ‘shallow gas’ pre-spud meetings with all concerned are a must. All contingencies must be covered & mutually agreed & written up for distribution prior to spud. After spudding Following spud, rig-site supervisors must ensure that hole & environmental conditions are continually monitored from spud to casing being set. Parameters that must be monitored include ROP, hole volume & return flow (if riser employed), geology (cuttings, MWD), swab & surge, prevailing weather & moon pool watch. Well control techniques relevant to top hole drilling must be employed

Formation Pressure Prognosis This can be prepared from Offset Well Data: • Mudlogging reports • Wireline/LWD logs • Direct Pressure Measurements • End-of-Well Reports Pore pressure estimates should agree with offset data, particularly with MDT/RFT results. Fracture gradient predictions should be based on LOT/FIT data and any discrepancies, such as Fracture Gradient predictions in excess of Overburden Gradient should be investigated. Pressure transition zones are particularly important to identify. Different pressure regimes are not normally separated by a sharp boundary but by a gradation, often tens of metres thick. It is important to identify the thickness of the transition zone and also the pressure gradients within. Fractures may transmit pressures to shallower depths and the crests of dipping permeable rocks may also exhibit higher pressures than the surrounding shales within a pressured clay section.


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Operations Geology Initial casing design is based upon the pore pressure and rock fracture estimates and the associated mud weight and ECD requirements. Remember that ECD will continue to increase when drilling horizontal sections although pore pressure and fracture pressure values may remain the same.

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Operations Geology

Figure 19: Pressure Profile


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Operations Geology Other Geological Hazards Gas Hydrates Gas Hydrates are compounds of frozen water that contain gas molecules. They look similar to white, powdery, snow and have one of two basic structures: • Small structure holding up to 8 methane gas molecules and 46 water molecules. This structure may also contain ethane, H2S and CO2. • Larger structure consisting of 136 water molecules with larger hydrocarbon molecules of pentanes and butanes. Gas hydrates only occur in high pressure-low temperature conditions in shallow arctic or deep oceanic sediments. In Alaska they occur between 750m and 3500m. They may have a shallow biogenic origin or, because of their carbon and helium isotope ratios, a crustal inorganic origin. They may appear as bright spots on seismic lines but their presence is only usually confirmed with drilling; penetration rates are typically slow and they have high resistivity and acoustic velocity coupled with low density.

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Operations Geology

Figure 20: Gas Hydrates

Hydrating Clays Mixed layer clays consisting of Illite/Smectite will exhibit hydrating and swelling characteristics due to the bound water in the mineral structure. The 2:1 layer clays consist of negatively charged mica-like sheets which are held together by chargebalancing counter-ions such as Na+ and Ca2+. In the presence of water, the counterions hydrate and the interlayer water forces the clay layers apart. The interlayer configuration, and therefore the swelling properties of the clay, is controlled by a number of factors including composition (total layer charge and charge location), interlayer cation (type, valency and hydration energy) and external environment (humidity, temperature and H2O pressure). Typically swelling clays are controlled by using oil based mud which does not have any free water to react with the clays to produce the hydrated material that will ball bits, restrict downhole circulation, and block flowlines and shale shakers. Otherwise the use of sea water and the addition of salts (K, Ca, Na) and various polymers will suppress this swelling tendency. Recently synthetic fluids based on olefins and esters and the addition of glycol to water based systems has also been used.

Hard Carbonates Thick deposits of carbonates can cause major drilling problems. They are rarely homogenous; the autochthonous chalks of the North Sea are generally low porosity


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Operations Geology whilst the allochthonous chalks are often very porous which contributes, together with extensive fracturing, to the oil and gas reserves of Norway, Denmark and Holland. Variable clay content, fracturing, recrystallisation, dolomitisation and the presence of flint and chert all have a major impact on the choice of bits and drillstring components. Commonly these rocks produce a harsh drilling environment with severe downhole vibration caused by bit bounce and stick-slip processes. Minimising weak points in the BHA is prudent so running MWD tools in these sections should be avoided if at all possible. If there are no objectives or operational decisions to be made in these rocks then the decision is relatively easy. If there is a need to steer the well through Chalk sections or if they are objectives then mud motors and vibration modules and thrusters should be used.

Evaporites The presence of salt will have a major impact on well design, particularly the mud and casing string. High pressures caused by squeezing salts need to be resisted during and after drilling and dissolution of salt is required by the use of oil based muds or salt saturated water based systems.

Tectonic Stress and Borehole Stability This will be a problem when drilling into highly dipping beds, across fault zones or in fractured rock. Ideally the well path should be aligned at 90º to the tectonic features, though this is rarely achievable. Borehole stability and hole cleaning is controlled by the drilling fluid. Mud weights, ECD, swab and surge pressures need to be closely monitored.

H2S The presence of H2S will have a significant impact on well design. H2S is a safety hazard and will affect wellsite operations. If the well is designated as an H2S well special training programmes will need to be available for all personnel together with the provision of specific PPE. H2S is also extremely corrosive; special H2S resistant drillstring components, casing and tubing will have to be supplied. Long lead times on this equipment can be expected.

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WSG Responsibilities Offshore Geologist Job Specification a. Key Result Area To supervise the acquisition of all offshore geo-seismic well information, interpret and evaluate the obtained data and communicate the results effectively according to the objectives in the Drilling Programme. b. Performance Indicators Attaining the highest possible standards of technical achievements with relation to safety and secure acquisition and evaluation of geo-seismic data. c. Responsibilities 1. To ensure that all relevant geological information from offset well is available on the rig. 2. Co-ordinate and supervise all geological operations and provide support and troubleshooting as and when required. Core handling, mudlogging, sampling, pore pressure evaluation, biostratigraphy and logging. 3. To ensure that all relevant geological data is acquired, recorded and of the highest possible quality. 4. To supervise the contractor personnel in the performance of their duties. 5. Perform and ensure compliance with all Quality Control requirements contained within the relevant QMS documents. 6. Maintain and revise existing Wellsite Geology work instructions based on post-well experience and new Government requirements. 7. Prepare and send daily geology reports and well data to Company, Government and partners 8. Proactively participate in daily offshore team meetings 9. At the end of each well section or during periods slow operations, collate the data in a way that it can be put straight into reports such as the Final Well Report. 10. Log and monitor MWD tools offshore and report to Offshore Well Supervisor 11. Evaluate MWD formation evaluation logs for changes in lithology and rock parameters. Use the data for correlating against offset wells. Report on the quality of the data received and operational efficiency of each run


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WSG Responsibilities d.Organisation Accountable to: Offshore Well Supervisors (Operationally) Operations Geologist (Functional and Technical)

Subordinates: None

Internal Interfaces: All members of the Drilling Team and G&G operations staff

External Interfaces: Service companies and Drilling Contractor.

Qualification Requirements a.Work Experience Essential • 6-8 years general wellsite geological experience with a minimum of 3 years offshore experience in the North Sea Arena. Desirable • Computer/keyboard skills and knowledge of reporting systems. • Knowledge of data formats • Knowledge of MWD and wireline logs • Knowledge of real time pore pressure evaluation

b) Qualifications • University degree or equivalent in geology/earth science. • Updated in issues related to wellsite geology • Fluent in the English language. • Leiro II Part I and Part III

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WSG Responsibilities • Knowledge of relevant Country Rules and Regulations.

c) Physical Make-up • Offshore Health Certificate

e) Abilities • Communications and team skills. • Setting of priorities and ability to meet deadlines. • Ability to perform under pressure.

Wellsite Geologist Wellsite Geology Responsibilities Planning Phase • Ensure adequate pre-job briefing. • Familiarization with Client policy and procedures. • Familiarization with well specific data requirements. • Familiarization with relevant software packages used for reporting, log drawing and communication. Operational Phase • Participation in rig safety meetings. • Liaison with key personnel (Operations Geologist, Well Supervisor, Mudloggers, Log Witness, Mud Engineer, FEMWD/geosteering personnel, Directional Driller, core contractor representative, Toolpusher, Driller, Radio Operator, etc. • Monitoring of operations • Responsibility for collection, QC and dispatch of geological samples • Responsibility for collection, QC and reporting of geological data • Responsibility for lithological description and geological interpretation


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WSG Responsibilities • Responsibility for core point selection • Responsibility for core retrieval and expeditious dispatch • Supervision of contractor personnel (mudloggers, FEMWD/geosteering contractor etc.) • Attendance and participation in relevant operational meetings and calls as operations dictate • Ensure good team working and communication when more than one wellsite geologist is at the wellsite (e.g. HPHT, geosteering, extended coring programmes, etc.) • Ensure adequate briefing and full documentation at crew change Post-well Phase • Ensure that geological data and samples are dispatched from the rig. • Ensure that geological computer hardware and consumables are secured. • Completion Log Finalisation

Safety and Certification The Wellsite Geologist must adhere to, the health, safety and environmental procedures specific to the work location. The Wellsite Geologist is required to participate in rig safety meetings and drills as required for each installation.

Preparation and Training The Wellsite Geologist must be familiar with the computing equipment and software, techniques and requirements that are to be employed at the wellsite:

Computing Equipment and Software Packages • Use of the PC network • Maintenance of the geological database and generation of reports • Completion / Lithlog drawing • Adobe Acrobat software to convert graphics files to (.pdf) format files • Business software

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WSG Responsibilities • Outlook e-mail • Schlumberger’s PDS View / Atlas Meta Viewer software • Zip software

Techniques • Sample preparation and description • Hydrocarbon show detection and description • FEMWD service quality control • Mudlogging • Core point selection • Core handling • Geosteering supervision • Biosteering supervision • Pore Pressure detection and prediction • Wellbore instability indications • HT/HP techniques • Petrophysical log operations witnessing when required including sidewall coring • Formation evaluation interpretation from FEMWD and wireline logs • Correlation.

Communications The Wellsite Geologist is required to maintain effective communications with the Operations Geologist and key wellsite personnel. All operationally significant communications and data should be copied to the following personnel: • Operations Geologist • Well Supervisor


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WSG Responsibilities All changes to the geological programme, or operational instructions will be directed to the Wellsite Geologist through the Operations Geologist. Where more than one Wellsite Geologist is at the wellsite, working practices must be adapted so that there is 24 hour geological cover. Work rotas should allow all the Wellsite Geologists to attend the morning operations meetings and calls. It is imperative that hand-over between shifts and/or between crews is seamless. Effective hand-over is a requirement and the responsibility of the all the parties involved. Any queries or clarifications that arise should be addressed to the Operations Geologist.

Geological Data Acquisition It is the responsibility of the Wellsite Geologist to collect and interpret the geological and operational data from all available sources. These data should be summarised in the Geological Morning Report, Mudlog and Completion Log/Lithlog. Geological interpretations influencing operational decisions (e.g. coring point, geosteering, casing setting depths etc.) should be communicated immediately to the Well Supervisor and Operations Geologist. The Wellsite Geologist is responsible for the collection, quality control, description, interpretation, reporting and dispatch of the following wellsite data: Samples • Cuttings samples as per sampling programme in the Drilling Programme • Mud samples as per sampling programme in the Drilling Programme • Sidewall cores as advised during logging operations • Hot shot samples as operations dictate • Additional samples (i.e. bottoms up samples, samples from the mud cleaning equipment, etc.) • During sustained fast drilling, the Wellsite Geologist may vary the sampling interval if it is impractical. Any variations of sampling interval should be documented and the empty sample bags, (where used), included in the sample boxes.

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WSG Responsibilities Conventional Cores The Wellsite Geologist is responsible for the following aspects of conventional coring: • Core point selection (as per the criteria in the Well Proposal Document) • Core handling, depth control and marking • Sampling for lithological identification and description • Preserved sample collection and preservation • Description and interpretation • Packing • Expeditious dispatch from the wellsite

Operational Data (subject to well specific requirements) • FEMWD curves • Operational detail • Lithological descriptions • Hydrocarbon show analysis • Mudlogging detail

Reporting Procedures On arrival at the wellsite, contact the Operations Geologist. Daily at 06:00, submit the following reports and logs to the Operations Geologist: (a) Geological Morning Report reflecting the geology, gas levels, ROP and operations that have occurred within the previous 24 hour period (b) Digital file of Mudlog, covering the section logged in the previous 24 hours. When appropriate, other logs such as the pressure log should also be attached with the report. (c) FEMWD logs at 1:500 scale in both MD and TVD acquired over the previous 24 hours. (d) Periodically send in CGM files of Geologist’s Field Completion Log/ Lithlog illustrating the geological interpretation over the previous section


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WSG Responsibilities Telephone updates to the Operations/Duty Geologist or geological support to the Drilling Supervisor as follows: (a) Morning rig call at designated time. (b) Afternoon rig call at designated time. (c) Ad-hoc updates as requested by the Operations Geologist. (d) At Any Time for geological support from the Operations Geologist or Duty Geologist. e.g. key decision points such as casing and coring). During coring operations; for each core as soon as available: (a) Core Report detailing the depths in MD and TVDSS, recovery, missing intervals, gas, ROP and geology (b) Core log at agreed scale (c) Core dispatch details (d) Sidewall Core Descriptions Miscellaneous: (a) Quality control report for the mudlogging service weekly (b) Quality control report for the FEMWD/Geosteering after each run (c) Sample dispatch details (d) Hot-shot sample dispatch details

Wellsite Supervision of Contractor Personnel The Wellsite Geologist is responsible for the supervision and quality control of the geological aspects of the following services whilst at the rig site: • Mudlogging (service quality control, sampling interval, gas detection, pore pressure detection and the accuracy of the Mudlog.) • FEMWD/Geosteering (data quality control, log transmission, data interpretation and geosteering recommendations.) • Coring (core handling, cutting, packaging and despatch.) • Biosteering (sample selection, data interpretation and biosteering recommendations.

Operational Guidelines The geologist should make every effort to maintain tight security on well data even when the well is not on tight hole status. All confidential data such as logs, reports etc. will be restricted to authorised personnel. No contractor personnel

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WSG Responsibilities should be admitted into the mud logging unit or the wireline logging unit, both of which should be locked when unmanned. On completion of the well the last wellsite geologist to leave the rig will extract from the file all working copies of exploration data and forward these to the Client.

Routine Sample Distribution When shipping samples from the wellsite it is important to follow the correct procedure, as specified below: Advance notification of all sample consignments should be made by fax or email (i.e. not included in the geological report or other reports) to Operations Geologist at the Client’s office. The message should specify the nature of the samples (i.e. stratigraphic, "Hot Shots", oil samples etc.), depth interval(s), means of transport, name and/or number of carrier, and estimated times of departure and arrival. Relevant information (i.e. well number, sample type, name of consignee and destination) should also be marked on the outside of the sample package. In the case of bulk or other samples brought onshore by boat the same general procedure will apply. It is important that all unaccompanied sample consignments should be listed on the boat or helicopter cargo manifest in order to avoid possible problems with customs and, also, to facilitate warehousing. Avoid the use of misleading descriptions when entering data onto a manifest, e.g. 5 litre sample tins should never be called paint tins as this implies hazardous cargo.

MWD Logging Duties Quality check all logs real time. Work with the MWD company and the Client Drilling Supervisor to ensure that the environment for high quality MWD data is attained. Try to evaluate the data for early signs of trouble as well as for formation evaluation. Send digital TIFF files (or equivalent) of FE MWD logs to the Client, partners and Government Agencies daily when the tool is in use during drilling. In the event of email outage the logs should be faxed. The MWD log should be used in conjunction with mudlog data to generate an interpreted lithology which will be displayed on the mudlog, completion log / Lithlog At the end of each MWD run a report should be produced noting the MWDservice, tool serial number, interval logged, circulating hours, drilling hours, relia-


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WSG Responsibilities bility of the data and usefulness for geological interpretation. Any problems should be noted and appraised with recommendation for further action or evaluation.. Lost time e.g. trip to replace MWD module etc. should be highlighted. As with wireline logging it is very desirable to try and tie in the logs with a previous run. Generally MWD companies do not recommend that the well is logged at more than 20 m /hr however, for tie in purposes logs can be run at up to 60 m/hr with certain companies.

Geological Morning Report Normally when new formation has been drilled a geological morning report should be transmitted at report time (0600 hrs) by email to Client and partners. A distribution list will been compiled for this purpose. The backup for email will be the telefax. Telefaxes to Client should be sent to; operations Geologist. The geological morning report will contain: • Well number • Report date • Present depth • Age of formation • Present activity • A detailed summary of lithologies drilled since the previous report • Formation tops • Gas reading • Hydrocarbon shows • Coring • DST / testing data where applicable

Any drilling/engineering data contained in the daily geological report should be verified by the drilling supervisor before distribution. In addition to the routine reports, the geologist should at his discretion send in supplementary reports whenever important information becomes available.

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WSG Responsibilities Distribution of these reports would normally be the same as for the geological morning reports. Geological issues requiring immediate attention should be discussed by phone or email with the duty geologist. Out of office hours contact with the duty geologist should be made by phone. Any geological report should be clear and concise and include any comments the geologist considers pertinent to the interpretation of the section based on his observation of the well data and his overall experience. Such comments may appear highly subjective at the time but are often extremely valuable to head office personnel. Long and detailed lithological descriptions should be avoided on these reports. Formation tops should be marked as preliminary and should indicate the information used to aid selection. Mudlogging Supervision It is the responsibility of the wellsite geologist to supervise the mud logging crew and to ensure that they perform their duties in a satisfactory manner. In particular, it is very important that the mud log is updated twice daily at shift change. Should the geologist consider any aspect of the mud logging service to be unsatisfactory he/she should report this to the Client drilling supervisor offshore and to the operations geologist onshore.

Completion Log & Lithology Log The wellsite geologist will not be required to compile an independent lithlog as this is simply a duplication of information. Instead, he should ensure that the mudlog is as accurate a recording of the data possible, and should play a major part in its compilation. Log draughting software will be available at the wellsite. This will be used for the generation of a Completion Log. During the course of the well the wellsite geologist should enter as much of the Completion Log data as possible, including graphic lithology, lithological descriptions, formation tops, cores, sidewall cores, RFT points, Two Way Time at formation tops, casing points, Mud Weight, Pore Pressure, Porosity and Water Resistivity in reservoirs, engineering data etc. This will minimise work required after completion of the well and has the further advantage that the compiling is done while the well information is fresh and freely available. Updates of this log should be periodically sent to Client as a.pdf or image file. At the end of the well a .pdf or image file of the draft version of the completion log should be sent to the Client. This will serve as a working copy until the final


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WSG Responsibilities version is made. Work on the final version of the completion log will not commence until all post well data required for the log has been received. The Field log is prepared on a 1:500 vertical scale using Resistivity/Sonic/GR data. The MWD logging contractor will supply this data on a disc in LAS / ASCII format shortly after completing each logging run. Final Completion Log should have the following curves: • GR (API) ROP (M/HR) CAL (IN) (Log Track 1) • RD & RS (OHMM) TGAS (%) (Log Track 2) • Sonic (US/FT) DEN (G/CC) CNC (V/V) (Log Track 3)

Back up scales should be used if necessary. A tension curve, is not required. Density and resistivity logs recorded inside casing should be removed from the display. (Note: the Field Log will have all log curves replaced using HQLD logs in the production of the Final Completion Log).

Draft Percentage Sample Descriptions The geological descriptions on the mudlog should primarily be those of the wellsite geologist. They should be compiled with the aid of "rock colour charts", supplied by the mudlogging contractor, and by conferring with other members of the team. Use of the MWD information and mudlog information should enable the wellsite geologist to create an accurate interpreted lithology column for display on the mudlog. Each cuttings sample should be described separately and manually on a "Wellsite Sample Description Sheet". Also, these descriptions should be registered electronically. The wellsite geologist should endeavour to enter each description into a word processor at opportune moments. The file should contain every sample description of the well for inclusion in the Final Well Report. The descriptions should incorporate percentage lithologies. The individual sample descriptions are extremely important since they form the ultimate point of reference for the lithology seen as the well is drilled. Lithologies should be described clearly and fully, with minimum use of such terms "As above". The end members of a long sequence linked by "As above" descriptions, may be completely different from each other. Each sample should be listed and any shows should be thoroughly described. This file will also be included in the Final Well report.

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WSG Responsibilities Coring The decision to core will be decided upon entering a sandstone with shows in the prognosed Jurassic sandstones. The operational decision process is bulleted below and fully outlined in the drilling program. • Resistivity close to bit (Resistivity 3m behind bit) • Flow Check drill break on 3m • Drill 5-8 m into top sst to identify increase in resistivity • Low resistivity suggests water wet rock – drill on • Increase in resistivity possible hydrocarbons (or increased cementation). • Cut 9m core (Use fluted aluminium inner barrel or pressure relief valves) (Use low invasion Core Head) (Use circulating sub above core barrel) • After breaking off core circulate annulus to above BHA, activate circulating sub and circulate annulus clean of hydrocarbons • POOH carefully (Do not jar barrel or trip at excessive speed) • At 1000m wait on core to degas (Do not RIH with core) • At 500m wait on core to degas. (Do not RIH with core) • The preferred handling on the rig is to minimise handling of the core. If it is possible to decide on continued coring from the base of the core then cap the core, mark the core barrel as outlined in appendix 2, cut into 1 m lengths and ship to town.. • Where possible take digital photographs of core / core chips and send as email attachments to town. • Minimise core handling and exposure to air.

Sidewall Cores Rotary sidewall plugs (RCOR) may be required for reservoir data, petrographic analysis, biostratigraphy and geochemistry. Sidewall coring points will be selected by the wellsite geologist in conjunction with the project geologist, after evaluation of the electric logs. Recommended coring points should therefore be


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WSG Responsibilities telefaxed or emailed to the operations geologist as soon as possible. Once the RCOR points have been selected all partners should be advised ASAP. Handling of these cores should be kept to a minimum as petrophysical measurements will be made on these plugs at the laboratory. On collecting of the plug from the tool, it should be gently wiped clean of drilling fluid and placed into a container. Each SWC container should then be labelled with depth, well number, date and other relevant data. A brief visual description of each core can be made by the wellsite geologist and the plug can be viewed under UV light. Under no circumstances should any fluids (water, acid etc.) be applied to the plug, nor should any part of the plug be rubbed or scratched. Once briefly described the plugs should be securely packed in the special boxes provided. SWCs and original descriptions should be despatched to the core laboratory by helicopter.

Pore Pressure Analysis The Wellsite Geologist will be knowledgeable and experienced in pore pressure evaluation techniques. During the well he will be in charge of monitoring the pore pressure utilising all sources of information including the FEMWD logs. He will work closely with the mudlogging data engineer to ensure that the well is drilled in as safe a manner as possible. In the event that a pressure engineer is offshore the wellsite geologist will work with him and the mudlogging data engineer to ensure a 24 hour quality appraisal of pore pressure is maintained.

Wellsite Geologists Final Well Report Content • Introduction • Stratigraphy • Proposed Versus Actual Well Results • Core Summary • Hydrocarbon Indications • Geological Samples Taken • Core Description • Completion Log (done offshore using Geo for Windows) • Formation Pressure

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WSG Responsibilities • Report on anything related to the pore pressure of the well under construction (the actual pore pressure and its deviation from what was planned, problems resulting from (unexpected) pore pressure). • Fracture Gradient Provide a table summary of all the casing shoe tests that have been performed. • Casing Size • Depth (TVD BRT) • Mud Weight (ppg) • Surface test pressure (psi) • Equivalent mud weight (ppg) • Type of test

Logging Witness Job Specification a. Key Result Area • Provide expert advice on the drilling rig related to wireline logging, to ensure quality control of the measurements and to gather all relevant petrophysical data in such a way that the objectives outlined in the Drilling Programme are being met. • To supervise the acquisition of borehole seismic survey information, interpret in-field and evaluate the obtained data to ensure quality control of measurements, and or gather all relevant geophysical data. b. Performance Indicators • That the wireline logging objectives are achieved and that a detailed log of logging operations is maintained. • That the wireline logging operations are carried out in a coordinated and safe manner without any unnecessary delays.


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WSG Responsibilities • That the petrophysical logs are reported in a timely and professional manner. • Attaining the highest possible standards in the acquisition of borehole seismic surveys through quality control. • That borehole seismic survey operations are carried out in a co-ordinated and safe manner in an optimal time frame. • That all data acquired for borehole seismic survey and site surveys is reported and transmitted for processing in a timely manner. c. Responsibilities • To ensure that all specified wireline equipment and personnel are available on the rig (and boat) with correct specification and/or certificates, to perform the service safely and efficiently. • To supervise all wireline logging operations and provide technical support and troubleshooting as required. • To ensure that all relevant petrophysical data is recorded at the required quality and that RFT samples are collected as per the programme and properly labelled. • Supervise all borehole seismic survey operations, providing technical support as and when required solely or in liaison with wellsite geologist(s). • Keep a log of the operation and report any deviation from the planned activities or any unplanned events without delay to the Senior Drilling Supervisor. • To report and agree any deviations from the Wireline manual with the Operations Geologist. • To immediately report and agree any deviation from Borehole Seismic Work Instructions Manual or scope of contracted service/planned activity with Senior Drilling Supervisor and Wellsite Geologist. • To prepare daily updates to the logging activities and analysis report. This should be passed on to the wellsite geologist for distribution to Company, Government and partners. • Communicate observations, interpretations and suggestions to the operations geologist.

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WSG Responsibilities • Verify the logging engineers tickets before passing onto the offshore supervisor for signing. Note on the tickets any disagreements and concerns. d. Organisation Accountable to: Drilling Supervisors (Operationally); Operations Geologist (Functionally and Technically) Subordinates: None Internal Interfaces: Drilling Supervisor, Wellsite Geologist and all members of the Drilling Team. External Interfaces: Formation Evaluation service companies; Drilling Contractor; Other service companies.

Qualification Requirements a.Work Experience Essential • 4 years petrophysical experience with a minimum of 2 years experience from the North Sea. Desirable • A broad experience in geology and petroleum engineering. Awareness of advances in the field of Borehole Seismic services. • Computer/keyboard skills b. Qualifications • Technical education. • Updated on technical issues related to wireline logging operations. • Fluent in the English language. • Leiro II part I and part II • Knowledge of relevant Country Rules and Regulations.


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WSG Responsibilities c. Physical Make-up Offshore Health Certificate d. Abilities • Communications and team skills. • Setting of priorities and ability to meet deadlines. • Ability to perform under pressure.

Supervision of Mudlogging Services General The operations geologist will meet with the mudlogging contractor and agree on the detailed services to be provided for each job. The discussions should decide on the formats of the log presentations, digital data formats, final report contents. The Formation Evaluation Log (mud log) will be prepared by the mud logging contractor at a scale of 1:500 in meters in a format agreed. Other logs required are: • Engineering Log at scale 1:1000 • Gas Ratio Log 1:2000 scale • Pressure Evaluation Log 1:1000 scale. The mudlogging company will supply all equipment and consumables agreed on in the scope of work of the contract. The unit will be equipped with Remote Data Management System Software and will be rig networked with 3 client workstations. The monitoring and analysis will cover, but not be limited to the following tasks • Total Gas Analysis • Chromatographic Breakdown of gas (C1 - NC4) • H2S analysis • C02 analysis • Drilling Parameters - Torque, RPM, PP, Flow in & Out, Temp in & out, WOB, PVT

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WSG Responsibilities • Calcimetry • Cuttings analysis - microscope, chemicals, Rock Colour Chart, Grain size chart, UV light box Ditch Magnet Remote • Data Management System Software data link Fingerprinting is a technique requiring the establishment of a base line for a parameter e.g. gas composition. Specific arrangements relating to finger printing analysis will be agreed at the wellsite between the data engineers and the offshore drilling supervisors.

Responsibilities The mudlogging geologists will work under the instructions of the wellsite geologist. They will be responsible for the collection of all cuttings and mud samples as outlined in the drilling programme. This includes 1 x 5 litre tin of unwashed cuttings, 1 x 1 litre tin composite geochem sample, 1 washed and dried sample and periodic mud samples. Mud samples will be taken on bottoms up at the end of each well section, before coring, before wireline logging, on entering the chalk, on entering the Jurassic reservoir and at 20 m intervals whilst drilling the Jurassic reservoir. At the end of the well the mud logger's crew chief will bring the complete well database and log plots to the contractor's field office for reproduction together with the contractor's "End of Well Report". One proof copy of the report will be sent to RFC, attention S.QSAPP. Also one proof copy of the CD will accompany the report. The CD will contain: • PDF file of the report • Tabular listings of all drill parameter and gas data • Text file of the lithological descriptions • All log plots in CGM format (EMF and PDF if CGM unavailable) • CGM or EMF & PDF file of any time based plots featured in the end of well report. A data listing at every 1m interval of all gas and drilling data should be output as ASCII and LIS files onto CD. After any amendments are made the final data package required is; 8 CDs 1 hardcopy report with included log prints 1 extra set of paper log prints (Sepia logs may be requested if partners unable to print image files).


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WSG Responsibilities Each morning the mud loggers will prepare a report covering the interval drilled and sampled, chromatography, pressure data, hydraulics and drilling breaks in the previous 24 hours. This report, will be used by the wellsite geologist and the drilling supervisor in the preparation of their daily reports. A single print of the up-to-date mud log covering new footage drilled should be supplied to the wellsite geologist, for use in the morning meeting. PDF or TIFF image files of the up-to-date mud log and other logs should also be provided for distribution with the morning reports. If there are problems relating to the email connection then the up-to-date mud log will be telefaxed to RFC, partners, and NPD. At the end of each bit run a ASCII file of drilling parameters and gas data parameters should be downloaded to floppy and given to the wellsite geologist for distribution to the partners. At the end of the well the mud log data disk for the entire well will be brought in to the mud loggers field office. The mudlogging contractor will arrange to transcribe this data to ASCII and LIS files on CD to be included in the mud logger's "End of Well Report". Drilling mud may have an effect on the detection of hydrocarbon shows. It is therefore important that the mud properties are closely monitored throughout the well. The senior mud logger must communicate closely with the mud engineer, obtain samples of mud constituents, and keep a time/volume record of significant quantities of materials added to the mud. Mud additives should be examined for fluorescence and other possible hydrocarbon indications, and a chromatograph profile should be obtained of all liquid additives, including diesel. Before and at regular intervals during the penetration of zones of interest, the mudloggers should take small reference samples of mud in the special cans provided by the mudlogging contractor for any oil samples. These mud samples should be taken from the flowline, labelled with depth, time and well name, then boxed and stored with the cuttings samples ready for shipment at the end of the well. At the end of the well, the Mudlogging contractor should be requested to provide a text file of all the sample descriptions. The senior mudloggers / data engineers, should compile an independent pressure analysis of the well utilising; drilling parameters Dxc trends gasses temperature cuttings shape LOTs & Direct Pressure measurements (RCI) Hole conditions (eg drag and fill on trips, )

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WSG Responsibilities The majority of the data provided will be depth based. However, during periods of very slow drilling or well monitoring, time based information maybe required, particularly if a non conformance has occurred eg a twist off, stuck pipe, a kick. Such data could be plots of torque time, or mud pit volume versus time. The mudlogging crew must be able and prepared to generate such plots as requested during the course of the operation. Where such events have occurred the mudlogging crew will note the event and report it in their end of well report. Plots of the time based evidence should be included in the end of well report and on the accompanying CD. The mudloggers will monitor the weight of metal collected from a ditch magnet and will graph it for each hole section. The metal should be collected from the magnet every100,000 drill string revolutions, weighed and plotted against depth. The purpose is to monitor casing wear and give early warnings of anything untoward happening. Any large metal fragments collected should be reported to the drilling supervisor immediately. Hydraulics calculations to be made for each BHA and hole section for the range of flow rates to be used. During wireline logging formation fluid samples may be recovered by use of the RCI tool. If opened at the wellsite the mudlogging crew need to be prepared to collect any gas samples and perform gas chromatography on these collected samples. Mudlogging crew will assist the wellsite geologist as and when required and particularly with core catching, preparation of preserved samples and core chip description and analysis During coring the mudloggers responsibilities include continual monitoring of coring parameter trends with feedback to drill floor to safeguard against drilling formation after core pack-off. If torque, ROP or stand pipe pressure vary substantially from the baseline, the core hand, driller, wellsite geologist and coring engineer should be notified. Coring parameters in paper form and electronic / ASCII format at wellsite to be provided to the wellsite geologist and coring engineer after each core run. Trip monitor information (depth of bit vs. time, instantaneous pipe speed) in electronic / ASCII format to be provided to the wellsite geologist and coring engineer at wellsite immediately after each core run. A paper plot of trip performance should also be produced for immediate discussion with the company man, wellsite geologist and core specialist, in case trip schedule requires modification. Analysis of drill string vibration while coring when MWD tools run above core barrel. Checking core on the drill floor for gas, (particularly H2S)


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WSG Responsibilities using a portable gas sniffer - when not undertaken by specialist company or rig crew.

Formation Evaluation, Pressure, Gas Ratios and Drill Parameter Logs The mudlogging contractor will prepare the Formation Evaluation Log at a scale of 1:500 in meters. The following items must all be routinely recorded on the mudlog: • Track 1: Rate of Penetration (m/hr), WOB (klb), RPM, MWD-GR (API),Date, Casing Shoe, Bit Run Number. Bit information: to include make, type, size, footage (m), time on bottom and motor, if used. Note: the detailed bit information should be placed on a bit record sheet and attached to the bottom of the log. On the log simply enter the bit run number • Track 2: Cored Interval • Track 3: Shows: giving fluorescence and cut ratings. • Track 4: Measured Depth (M - BRT) • Track 5: TVD (M - BRT) • Track 6: Cuttings Lithology Percent • Track 7: MWD deep resistivity (ohmm), Total Gas - avg (%), Total Gas max (%), trip gas and connection gas annotations • Track 8: Chromatographic analysis: C1, C2, C3, iC4, and nC4, (ppm). • Track 9: Calcimetry results • Track 10: Interpreted Lithology • Track 11: Lithology Descriptions and comments. Lithology description and remarks column: to include a full lithological description and operational details such as casing, logs, surveys, cores, wireline logs run, mud data etc. Brief mud reports: every 500 m or whenever the mud properties are changed. Tails can be added to the log to contain detailed information related tologging runs, sidewall core descriptions, core descriptions, RCI pressure data and points sampled, DST data

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WSG Responsibilities Gas Ratio Log • Track 1: Average ROP (M/HR), GR (API) • Track 2: Measured Depth (M - BRT) • Track 3: Interpreted Lithology • Track 4: Total Gas - average (%), Resistivity (ohmm) • Track 5: Chromatographic analysis: C1, C2, C3, iC4, and nC4, (PPM). • Track 6: Oil Character Qualifier • Track 7: Wetness Ratio, Light to Heavy ratio Log header to contain algorithm used to define Oil Character Qualifier, Wetness ratio and Light to heavy ratio

Drilling Parameters Log (Engineering Log) • Track 1: ROP (M/HR), WOB (KLBS) • Track 2: Measured Depth (M - BRT) • Track 3: Interpreted Lithology • Track 4: RPM, Torque - Average (ft-lbs), Torque - Maximum (ft-lbs) • Track 5: Flow rate (GPM), Standpipe Pressure (PSI) • Track 6: Mud Weight in (SG), Mud Weight out (SG) • Track 7: Total Gas - maximum (%), Total Gas average (%) • Track 8: Remarks (Keep lithology descriptions brief)

Pressure Evaluation Log • Track 1: WOB (KLB), ROP (m/hr), RPM, Torque (Ft-lbs), MW (SG),ECD (SG) • Track 2: Depth (M-BRT) • Track 3: Total Gas - average (%), Trip Gas, Connection gas, Dummy connection gas • Track 4: Temp in (C), Temp Out (C), Differential temp (C)


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WSG Responsibilities • Track 5: Dxc • Track 6: Pore Pressure (SG), Fracture Pressure (SG), OBG (SG) • Track 7: Interpreted Lithology Track 8: Comments. Note particularly pit gains, LOT, drag and fill on connections, cuttings shape

Reporting The final data package required is; • 8 CDs • 1 hardcopy report with included log prints • 1 extra set of paper log prints

The report will contain the following information: • Introduction • Summary information • Casing Summary • Logging Services • Rig Equipment • Events by hole section • Geological discussion • Pressure Discussion • Data Summaries • Bit and Hydraulic Data • BHA Data • Drag Plots On / Off bottom • Torque plots On / Off Bottom Pressure Plots

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WSG Responsibilities • Appendices • Formation Evaluation Log • Engineering Log • Pressure Evaluation Log • Gas Ratio Logs • Time based plots (if required)

Note: Any issues related to geohazards such as gumbo, stuck pipe, vibration related problems, inflows to the well, significant mud losses etc, should be discussed in detail in the appropriate section of the report. Time based prints should be used, if necessary, to elaborate on the incident under discussion.

Remote Data Management System Software Where Remote Data Management System Software or equivalent data management and transmission system is being used the following displays will be available for selection by remote logon users; • Drilling Display • Mudlog setup • Engineering Display • Engineering log setup • Pressure Display • Mudlogging Pressure Evaluation Log setup • Gas display • Gas Log setup • FEMWD Display-FEMWD log setup • Vibration Display- Vibration Log Setup • PWD Display-P W D Log setup


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WSG Responsibilities • Tripping Display • Cementing Display • Testing Display

MWD specific guidelines Data acquisition programme This is schematically shown in figure 1. A full discussion regarding the FEMWD and wireline logging programme is given in the Drilling Programme. • The 36" Hole to 170m requires a MWD DIR OD 9.5" • The 9 7/8" Pilot hole requires a MWD/DIR/GR/EWR4 OD 8" • The 26" / 20" hole requires a MWD DIR OD 9.5" • The 17.5" hole require a MWD/DIR/GR/EWR4 OD 9.5" • The 12.25" hole requires a MWD/DIR/GR/EWR4/PWD/VIB OD 9.5" • The 8.5" hole requires a MWD/DIR/GR/EWR4/PWD/VIB OD 6.75"(A BAT tool may be added after coring.) Whilst the tools are modular they are made up onshore and sent to the rig.This means that there will be a significant amount of mobilisation and demobilisation required through the course of the well. The BAT tool can be added to the bottom of the MWD assembly at the wellsite if required. As soon as the logging engineer arrives on the rig, the geologist shall review the MWD logging program, logging parameters and MWD Specific Guidelines to ensure that there is no misunderstanding about what is required.4.1.3The MWD program has been designed to achieve a number of objectives including hole verticality, knowledge of wellbore spatial position, OBM fluid dynamics pressure modelling, shallow gas identification, reduced vibration related problems, hydrocarbon reconnaissance logging, core point picking, and geological correlation with offset wells. The geologist should use the MWD logs for correlation, tops picking and evidence of hydrocarbons. A primary purpose of the logs is for the evaluation of pore pressure whilst drilling. At the wellsite one field print will be required at the end of each run. Daily printouts and image files will be required whist drilling.

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WSG Responsibilities The logging contractor's Real Time Acquisition Tape will be hand carried to the service companies office at the end of the job by the logging engineer. At the end of each section of the well the MWD operator should splice all FEMWD log runs together and save this to disc. The survey data should also be included as a separate LAS or ASCII file. Four paper prints should be made of this spliced log. The data disc, verification listing, log plot and image file to be sent to MWD Contractor for QC. Two log prints to be sent to RFC office and one copy to be retained at the wellsite. • At the end of the well the MWD contractor will provide to RFC: • A composite set of FE curves from memory data, on tape or CD in LIS or DLIS format • All the unspliced FE data (and full waveform data where applicable) for each MWD run on tape or CD in DLIS or LIS Format Verification listing of the data tape / CD. • A complete survey listing of the entire well in LAS format • Six paper log prints of the FE logs at 1:200 scale (separate from the report) • One end of well report including log prints. The report is also to be provided in digital PDF format • PDF, EMF & CGM files of all log prints (Sepia logs may be requested if partners unable to print image files) The draft report of all MWD activity during the well should be prepared and forwarded to RFC with one week of completion of the well. All non-conformances must be addressed in the report. The final report should be delivered to RFC within 6 weeks of the end of the well. The report will contain the following: • Description of each BHA MWD run, including bit type Performance of each MWD run and a brief description of the lithologies drilled • Details of any problems encountered (engineering or geological) during the MWD run Section relating to the findings of the PWD data. The tool is run in the well to compare actual downhole pressures with the mud hydraulic modelling program. The tool may also highlight good and bad drilling practises or supply useful information in the evaluation of an unexpected event whilst drilling or tripping. All these should be addressed.


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WSG Responsibilities • Time based example plots over limited periods should be generated to highlight examples being discussed in the text Section related to the vibration sensor results. Note the settings used for activation of caution and stop alarms. Note action taken through use of the information • Tabulated listing of the survey data • Battery Life monitoring records for each tool • Composited MWD FE log plot Composited Depth Vibration Log plot • Details of all splicing of MWD runs • Details of all post well processing e.g Shear velocities from Sonic data. This section to include QC semblance plots and other QC plots. • Section giving statistics relating to overall tool reliability. • The compiled monthly reports calculating Mean Time Between Failure (MTBFF)should be included here. The statistics to include • Total Operating time lost • Total Circulating Hours • MTBFF Highlights and Lowlights • Section containing details of tool failures giving details of the problem, tool serial number, cause, action taken, closed out or open.

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WSG Responsibilities Wireline Logging Procedures In the event that an RFC log analyst is not at the wellsite, the wellsite geologist shall supervise all logging operations. He/she will make sure that all log headings are complete and correct and instruct the mud engineer or mudlogger to have circulated mud samples ready for the logging engineer at the beginning of the logging job. Any difficulties experience during logging, and any anomalous log responses should be noted on the “Remarks” section of the log header. On arrival at the wellsite the logging engineer and the wellsite geologist should go over the mudlogs and MWD logs of the section to be logged and review the objectives of the wireline programme. The Wireline Specific Guidelines and logging parameters should also be reviewed to ensure that there are no misunderstanding regarding requirements from the job. A repeat section of at least 50 m should be recorded over a zone where log responses show large variations, e.g. a sand/shale sequence. Additional repeat sections should be run over any intervals which show anomalous log responses. All logs (with the exception of the NMR and resistivity logs) should be run at least 50 m up into the casing. If no casing has been run since the previous logging run then all logs should overlap the previous run by at least 50 m. If a continuous temperature log is not being run in combination with the cable tension head then 3 thermometers should be run on all logging sondes, and the maximum temperature is to be recorded on the log header. All logs must be digitally recorded on magnetic tape or CD. Field prints of all logs are to be produced on both 1:500 and 1:200 vertical scales. Each 1:200 scale log with wall contact or centralised logging tools should have a cable tension curve recorded on the least crowded track. Repeat sections part to be attached to the 1:200 print. QC logs should be included as part of the final log print. If difficulty is experienced running logging tools to the bottom of the hole, the engineer will in any case log out from the deepest point reached bearing in mind that the tool may stick at a shallower depth on subsequent runs. At the wellsite four (4) sets of prints will be made of each log. One set of prints will be retained at the wellsite. Two (2) sets of prints should be packed in a separate envelope, marked "Exploration Dept, attention Ops. Geologist", and 1 set of prints are to accompany the raw data tape to Logtek, via the wireline companies office. (Sepia logs may be requested if partners unable to print image files)


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WSG Responsibilities The logging contractor's Real Time Acquisition Tape and the original log will be hand carried to town at the end of the job by the logging engineer. The tape will also contain a full set of presentation and raw logs for the repeat section. A copy of this tape should be sent to Logtek with a verification listing and a paper print of the log. All tools outlined in the logging programme for the section of the well will be required to have a backup. The backup to the RCI for the 12.25" hole section will be the FMT. All logging tools should be accompanied by appropriate wireline cutting equipment, fishing tools and other attachments that may be required to aid logging e.g. a hole finder. Pipe conveyed logging equipment should be available onshore for mobilisation at short notice, when not specified in the logging programme. After logging all tools that are on rental should be returned to base on the first available boat to minimise rental charges. Note. A GR/FMT run may be required before coring in the 8.5" section. These tools should be left onboard whilst drilling the 8.5" section. Data Requirements At the end of each logging run the Logging Engineer will provide the witness with: • A floppy disk containing the main FE curves acquired (LAS Format) • A log print of the data acquired METAVIEW / PDS / TIFF file of log print • Header information (Mud type, MW, Vis, BHT, Rm & RMF ifappropriate) At the end of the job the logging engineer shall supply the witness with: • 4 field prints • Printout of logging diary (note the witness and logging engineer shall discuss and agree on what was downtime, non productive time and operational time. Job tickets to be verified by witness and authorised by the drilling supervisor The engineer will take the data tape to the contractors office and generate Digital data tapes or CD containing full waveform data of all display and raw logs, including repeat section logs (LIS Format).

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Wireline Logging Introduction Electric logging services were introduced by Schlumberger in 1927. The first resistivity log was hand plotted from point data and designed to help identify the location of reservoir rocks and hydrocarbon bearing formations. Since then, of course, the sophistication, range and quality of logging operations has increased dramatically but the principle aims remain largely the same. Petrophysical logging tools are inserted into the borehole, usually at casing points, and the hole logged whilst retrieving the tools to the surface. Traditionally the tools are conveyed by wireline which also provides for tool operation and data communication. Typically measurements of natural radioactivity (Gamma Ray Log), formation resistivity, and porosity (Sonic Log, Neutron Porosity Log and Bulk Density Log) are measured in the open hole section. Some radioactive tools can measure through casing. Recently, high definition azimuthal tools have enabled images of the borehole to be produced that can show bedding, dip, fractures and other geological and geoengineering features. Early electric logging was largely qualitative and it was not until the 1940s when Archie (working for Shell) developed mathematical models for quantifying hydrocarbon saturation. Tool conveyance methods have also widened over the years. In tough conditions such as high borehole inclination or poor hole quality, logging tools can be conveyed by drillpipe or coiled tubing; some companies such as Reeves Wireline have also developed tools powered by batteries so eliminating the need for wire cables in these cases. Since the late 1970s Measurement While Drilling (MWD) services have also been developed with logging tools incorporated into the drillstring to facilitate logging during the drilling processes. This provides valuable data for real-time geosteering operations as well as reducing the need for traditional “wireline” type needs.

Operations & Wellsite Geologist

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Wireline Logging

Figure 1: Wireline Logging Operations

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Wireline Logging

Figure 2: Logging Equipment Setup (Reeves Wireline)

Logging Tools The tools, or sondes, typically contain a variety of transducer with associated power supplies, measurement systems, analogue-digital converters, processors and communications electronics, encased in a stainless steel pressure casing. The tools are supported and powered by a cable which may contain seven or more electrical conductors. The surface equipment comprises a cable drum, motor and gearbox capable of running into and out of the hole quickly and of providing a smooth, stable pulling speed during logging. The length of the cable is measured with a depth wheel over which the cable passes. The tools vary in length from about 1m- 6m, with modern trends being towards more compact tools for ease of handling and deployment in tough logging conditions.


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Wireline Logging Historically many tools had to be run by themselves, thereby increasing time and costs; today most tools are combinable and basic measurements of gamma ray, resistivity and porosity can usually be made in a single run. For example, Schlumberger’s Platform Express service measures gamma ray, neutron porosity, bulk density, photoelectric effect (Pe), flushed zone resistivity (Rxo), mudcake thickness (Hmc), also called pad standoff, and true resistivity (Rt) derived from laterolog or induction imaging measurements in one tool 12m (38ft) long. Their previous integrated tool (the Triple Combo) came in at 27m (90ft).

Figure 3: Platform Xpress (Schlumberger)

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Wireline Logging Reeves Wireline have Compact services with tools of 2.25” O.D. for use in slim holes and tubing conveyed applications. Their triple combo is 9m (29ft) long and the heaviest tool weighs just 41Kg (90lbs). Many of these tools are also available as CML tools (Compact Memory Logging) powered by a battery pack which means there is no need for a wire cable when conveyed by tubing. data are stored in non-volatile memory, recorded every half second, and converted into depth logs when recovered to the surface. CML tools mean that data can be collected in holes that were not previously logged for technical or financial reasons. When conveyed with drillpipe there is no wireline, side-entry-sub or wet connect to slow the process down.


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Wireline Logging

Figure 4: Log Header

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Wireline Logging

Figure 5: Main Log


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Wireline Logging Measurements Traditional open hole logging normally includes the following tools and associated data.

Gamma Ray This records naturally occurring gamma radiation which originates from the radioactive isotopes of Potassium (K40), Uranium (U238) and Thorium (Th232). In sedimentary rocks these have low abundance in sandstones, siltstones and carbonates, but generally high abundance in clays and shales. Basic tools record total gamma ray abundance in API Gamma Ray units which is defined as 1/200th of the difference between high and low radioactive concrete in the API test borehole at the University of Houston. The tools typically have scintillation detectors recording radioactive events which are counted and recorded. Because of this, logging speeds need to be kept relatively low in order to have enough time to make statistically valid interpretations. Generally logging speeds of 1800 ft/hr are the norm with nuclear tools.

Figure 6: Spectral Gamma Ray Log Interpretation The gamma ray tool is used as a geological correlation tool, across multiple wells and also between logging runs in the same borehole. As a first pass, high gamma values are deemed to be clays and low gamma values, not clays. A sand-shale

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Wireline Logging sequence will, therefore, have a typical response of alternating high and low gamma ray values. Carbonates, (limestones and dolomites), will also tend to have low gamma responses. However, other minerals may also have higher than minimal gamma values making overall lithological determination less straightforward where the lithologies are more complicated and the sands more shaly. Orthoclase feldspar, micas, glauconite and some evaporites (sylvite, carnallite, polyhalite) all have high potassium content which could lead to misinterpretation. Uranium tends to be preserved in reducing conditions so that typical source rocks (deep water, dark coloured, organically rich clays and shales) often have significantly higher gamma values than other fine grained clastic rocks. Spectral Gamma Ray This records not only the number of gamma rays but also their energy; this in turn allows the elemental concentrations of K, U and Th to be estimated. Spectral analysis can be very helpful in complicated lithologies such as shaly sands, arkoses, micaceous sands, and source rock identification. It can also help with clay mineral determination which can often be important in drilling operations: smectite rich clays (bentonite/montmorillonite) react with fresh water to hydrate and produce a viscous mush, (gumbo), which interferes with mud circulation, impedes hole cleaning and generally slows down the drilling process.

Shale Volume Whilst the gamma ray log is mostly a qualitative geological correlation tool it can be used, with others, to provide an estimate of the shale content of sandstone reservoirs. Shaly sands produce errors in porosity estimations from the neutron porosity log and the density tool and also reduce overall resistivity values. Hydrocarbon saturation is computed from resistivity and porosity data using the Archie formula. If we assume that high gamma values represent shales and low gamma values represent clean quartz sands then higher than minimal values of gamma ray in sands can indicate the amount of clay content, (Vcly or Vshale). This, in turn, can be used to correct porosity values and obtain truer estimations of formation resistivity (Rt) for saturation calculations. Shaly sand models are normally used for saturation instead of the basic Archie formula. Commonly used formulae are the Simandoux and Indonesia models.


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Wireline Logging Density Logs Density logs are used to estimate porosity, establish compaction trends and identify overpressured rocks. The photo-electric factor (Pe) can also be used to help identify rock types. A gamma ray source is required to fire collimated gamma rays into the formation. The source is typically chemical (Cs 137) although Schlumberger have a tool which uses an accelerator. This is generally safer than a chemical source since radiation is only emitted when the tool is switched on downhole. There are typically two gamma detectors around 1.5m and 4.0m from the source. Gamma rays interact with atomic electrons in three ways: • Pair production • Compton Scattering • Photoelectric Absorption

Figure 7: Density-Neutron Log

Pair Production At energy levels above 1.02 MeV the incident gamma rays produce positronelectron pairs. This is usually well above the energy of gamma rays from a

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Wireline Logging chemical source (662 KeV), and so can be discounted in most logging operations.

Compton Scattering This is the main interest in density logging. Incident gamma rays collide with, and are scattered by, orbital electrons, losing some of their energy in the process. The number of scattered gamma rays available for detection depends on the electron density of the material through which they have passed. This is converted into bulk density for data collection and log presentation: Z ρ e = 2 --- ρ b A

Photoelectric Absorption This is the absorption of low energy gamma rays by atomic electrons, together with spontaneous photon emission.The photo-electric cross section index, Pe, measured in barns/electron*, is a measure of the probability of this interaction occurring and is strongly dependent on the atomic number, Z, of the nucleus of the target atom. Thus Pe is sensitive to rock chemistry and can be a useful lithology identifier. Values of Pe for the common reservoir rock forming minerals are: Quartz:1.8 Calcite:5.1 Dolomite:3.1 * 1 barn = 10-24 cm2

The presence of weighted muds can have a detrimental effect on lithology identification from Pe since barite has a Pe value of 267 barns/electron which can completely overshadow to rock mineral values. This may be less of a problem in LWD logging operations since the invasion process will not have had as much time to develop.

Dual Detectors Density tools have dual detectors, both reading in the flushed zone, in order to make a correction for standoff (mud cake thickness) and the effect this will have on accurate density values.


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Wireline Logging Porosity Estimations Porosity can be estimated from bulk density values if the lithology and dominant pore fluid type are known. Since: ρ b = φ ( ρ fluid ) + ( 1 – φ ) ( ρ matrix ) then:

ρm – ρb φ = -----------------ρm – ρf

Neutron Porosity The most common neutron porosity tools are based on dual spaced thermal neutron detection. Fast, high energy neutrons from a chemical source, (usually Americium-Beryllium), are slowed the thermal energies by collisions with nuclei in surrounding materials. Most energy is lost in collisions with nuclei of similar mass; in this case hydrogen nuclei. Since hydrogen is normally only present in pore fluids the porosity can be determined from the hydrogen index. However, bound water in clay minerals can make the neutron tool a sensitive shale indicator. The mean distance travelled during this phase, the Slowing Down Length, is controlled largely by the density of hydrogen in the formation. Once at thermal energies the neutrons are available for capture or detection in one of two helium3 detectors. The mean distance travelled prior to capture is the Diffusion Length, the principle control on which is the Chlorine content. Thus the ideal neutron log should be sensitive to the Slowing Down Length only. By using two detectors to measure neutron energy reduction, the ratio of near far counts can give a reasonable porosity approximation. Epithermal neutrons are insensitive to Diffusion Length and therefore not affected by chlorine content. Until recently, however, poor count rates have may repeat ability of epithermal tools unreliable. Neutron tools are calibrated so that they read true porosity in clean, freshwater filled limestones. Corrections are normally required when investigating other lithologies and also when significant gas saturations are present.

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Wireline Logging Sonic Log Sonic logs measure velocities and waveforms of acoustic signals in the near wellbore environment. Velocity is determined by timing a sound pulse as it traverses a known distance through the rock. The sound pulse is generated by one or more transmitters and the sound energy propagates a compressional wave through the borehole fluid until it encounters the borehole wall at which point part of the incident energy is refracted into the rock where it initiates compressional and shear wave particle motion. The wavefronts travel at different speeds, compressional waves being the fastest. Energy is radiated back into the drilling fluid as compressional energy and some of this is detected by receivers spaced along the tool. The first arriving wave being the compressional energy. Shear energy within the rock leaks back into the borehole as compressional energy but only if the rock shear velocity is greater than the fluid’s compressional velocity. Measuring the time difference between arrivals at two receivers eliminates the common time spent by the signal in the borehole and enables the time spent in the rock to be determined. This provides the interval transit time, or delta-t, (∆t). When divided by the receiver separation the log becomes an inverse velocity or slowness log. Units of slowness are microseconds per foot or per metre, (µ sec/ ft or µ sec/m). Values of µ sec/ft (compressional wave), for common reservoir rock minerals are: Quartz:55 Calcite:49 Dolomite:44

Porous sandstones, limestones and dolomites will have increasing travel times from the matrix values. Pore fluid travel time will also affect overall values. Seawater or salt water drilling fluids typically have µ sec/ft (compressional wave) travel times of around 180. Sonic logs are often scaled from 40-140 µ sec/ ft since sedimentary rocks will rarely have values outside these limits.

Porosity Estimations Porosity estimations from sonic logs require information about matrix and fluid travel times, as is the case with the density log.


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Wireline Logging Porosity can be calculated as follows: ∆t – ∆t m φ s = ---------------------∆t f – ∆t m This works best in clean formations of moderate porosity. At high parasites wave propagation may not be as effective and therefore porosity estimations may be compromised. Algorithms and correction charts are provided by the vendors in order to make suitable corrections.

Resistivity Logs Electrical logs measure formation resistivity in order to determine fluid type; since the only conductive part of the rock is salty water, low formation resistivity normally represents water filled porosity while high resistivity may indicate the presence of hydrocarbons. There are two basic varieties of wireline tools depending upon drilling fluid type:

Electrode (Guard) Logs The modern version of this is the Laterolog. Current is emitted from a transmitter and prevented from travelling straight up the borehole through conductive drilling fluid by the presence of guard electrodes at either end of the tool. The current is detected by receivers on the tool. The distance between the transmitter and the receiver is called the spacing; this affects the depth of investigation and the vertical resolution. Longer spacing provides deeper investigation but poorer resolution. Modern tools utilise multiple transmitters and receivers in order to obtain a number of depths of investigation and resolution curves. The Dual Laterolog, for example, has a a deep (LLd) and a shallow (LLs) reading together with a micro-resistivity device (usually Micro-spherically focused or MSFL) to record the flushed zone resistivity. Separation of different spacing curves usually indicates fluid invasion and therefore, rock permeability.

Induction Tools When a non-conductive drilling fluid is being used, such as fresh water or oil based mud, then electrode type logs will not work. Induction logs have a series of electrical coils through which an alternating current is passed. This produces a magnetic field which induces a current to flow in the formation. This induced

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Wireline Logging current sets up a secondary magnetic field which influences the AC current flowing around the coils. The interference can be detected and used to compute the resistivity of the formation. In fact, this tool measures the conductivity of the rock which is normally converted to resistivity for plotting on the log. Since the tool is measuring conductivity it may give slightly lower resistivity values than laterologs if there is formation heterogeneity.


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Wireline Logging

A2

28ft

A1 M2 M1 A0 M'1 M'2 A'1

A'2

Rxo pad

Figure 8: Dual Laterolog Tool

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Wireline Logging Other Measurements Other measurements may be taken and tools run according to operational requirements:

Caliper Caliper logs measure the size of the borehole. Most are mechanical devices using the spring-loaded arms on pad sensors, (micro-resistivity; density; neutron porosity), to measure the borehole diameter in one or more azimuths.

Formation Pressure The Repeat Formation Tester (RFT) tool is able to measure formation pressure and take fluid samples from permeable zones. Using a pad, which is squeezed up to the borehole wall to remove mud hydrostatic pressure, and a probe which penetrates the reservoir rock flowing pressures and shut-in pressures can be recorded at multiple depths. Two fluid samples can be collected for surface evaluation. Modern derivatives such as Schlumberger’s Modular Dynamics Tester (MDT) can be configured in a variety of operational set-ups, may use multiple probes, collect many fluid samples and using on-board resistivity and optical recognition technology, identify fluid types downhole. By taking multiple pressure readings at different vertical depths through the reservoir fluid pressure gradients can be established which will identify fluid types and, at the intersection points of fluid gradients, fluid contacts.


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Wireline Logging

Figure 9: Schlumberger MDT Tool

Imaging Logs By taking closely spaced readings at multiple azimuths around the borehole imaging logs can provide “pictures” of the borehole and geological features. Using density, resistivity and sonic measurements imaging logs can show dip and bedding, fractures, secondary porosity and borehole geometry features.

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Wireline Logging Whilst normally available only after drilling some LWD tools such as Schlumberger’s ADT (Azimuthal Density Neutron Tool) service can provide useful information in geosteering applications.

Figure 10: Schlumberger FMI Tool


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Wireline Logging

Figure 11: Image Log Concepts

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Wireline Logging

Figure 12: FMI Scan


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Wireline Logging Lithology Identification Most of the logging tools described above can be used for lithology identification, particularly when two or, more data sets are cross-plotted. Trends, repeated sections and curve shapes can also give indications of facies and environments of deposition.

Gamma Ray The Gamma Ray is initially thought of as a shale indicator. Typical reservoir rocks, sandstones, limestones and dolomites are likely to have low levels of potassium, thorium or uranium bearing minerals and, therefore, low overall gamma ray values. Shales and clays are likely to have high gamma ray values. API Gamma Ray units are designed to give values readings of about 100 units in “average” clays. But, of course, this depends upon the exact clay mineralogy. Basic geological correlation can therefore be done with the Gamma Ray for comparing sections over different wells and also between logging runs on the same well. It is also used as a depth correlation tool for matching up different curves and for locating shot depths for sidewall cores and for depths for pressure tests and fluid sampling with RFT/MDT tools. Even clays and shales will have variations in gamma ray count according to their mineralogy; illite clays (because of potassium binding the clay layers together) have high counts whereas smectites (including bentonite and montmorillonite) will have lower counts because of their water, rather than potassium, bonding. Most clays are of mixed and variable mineralogy and so will have intermediate gamma ray values. Other minerals with significant potassium content include: • Orthoclase Feldspar • Micas • Glauconite • Evaporites (Sylvite, Polyhalite, Carnalite) This means that arkoses, micaceous sandstones, glauconitic (green) sandstones and certain evaporite sections may have gamma ray values well above “expected minimums” and could cause interpretation difficulties. Gamma Ray and Grain Size There is a potential correlation between gamma ray count and grain size in clastic sediments. Clay minerals (potentially rich in K40) are more likely to be associated with fine sands and silts than coarser sediments because they will tend to be

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Wireline Logging deposited in lower energy environments. Thus they will tend to have higher gamma ray values than coarser sands and conglomerates. This is nothing to do with the (quartz) grain size as such but just with the likelihood of associated clay minerals. If there are no clay minerals in the particular environment then none will be deposited and the correlation will not exist. Often, however, not only variations in gamma ray count can be seen but definite trends of changing values can be identified. Increasing gamma ray count upwards in a sand reservoir may indicate a fining upwards sequence; decreasing upward values may indicate a coarsening upwards section. The former may represent a channel and the latter may represent a beach or barrier development. These trends may also be seen on density and resistivity logs.

Photo-electric Absorption As already discussed the Pe value can identify reservoir rocks when the influence of weighted muds (the associated barite) is not great.

Density - Neutron Crossplots By themselves, density and neutron porosity curves are rarely definitive lithology identifiers. For non-porous, mono-mineralogical rocks such as evaporites the bulk density will be able to identify the lithology. Halite and Anhydrite, for example, are readily identifiable from their very different densities if the beds are thick enough to be seen. With porous rocks, however, it is necessary to cross-plot data in order to define the dominant mineral. Log interpretation software can produce such cross-plots and the vendors also supply charts to perform the task manually. Such cross-plots work best in clean, (clay free), liquid filled formations. Gas content will drag densities down and decrease apparent neutron porosity whilst clay will increase porosities and effect density values according to the relative density of the clay minerals to the dominant quartz, calcite or dolomite of the reservoir rock.

Sonic Log The sonic log is reflecting rock density so that its response is similar to the bulk density tool. Again, on its own only certain lithologies are identifiable but when cross-plotted with density and/or neutron porosity, dominant mineral assemblages can be identified. Halite at 67 µsec/ft, Anhydrite (50) and Gypsum (52) can often be identified directly from the sonic but porous rocks will have a range of travel times.


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Wireline Logging Resistivity Log The resistivity log is primarily used for saturation determination. However behavioural trends can help identify environments and facies and absolute resistivity values can help identify lithologies. Tight or impermeable rocks, for example, will have high resistivities whilst porous, water filled formations will have low values. Again, resistivity is based used in conjunction with other curves for lithology investigation.

Curve Geometries Visual examination of the curves, particularly the arrangement of the densityneutron curves, can indicate rock type. Density-Neutron Porosity curves are plotted on the same track using compatible scales. Since the Neutron Porosity tool is normally calibrated in Limestone Porosity Units the density log scale will have 2.70 gm/cc aligned with 0% apparent neutron porosity. This means that in clean, liquid filled limestones the apparent neutron porosity read from the log will be the correct value and the density and neutron curves will overlay one-another. However in different lithologies the log porosities will need correction and the density and neutron curves will not overlay. In water filled, shale free sandstones, the separation between the curves will be around 3-6 porosity units with the density curve showing a slightly higher apparent porosity. Oil will produce a reduction in density values whilst gas will also cause a reduction in apparent neutron porosity values leading to further curve separation. Shaliness will cause the neutron curve to read high apparent porosities with a slight change in density according to the clay mineralogy in both carbonates and sandstones. The gamma ray will show higher values than clean formations. Clay and shale beds will have high gamma ray values and large separation between the density-neutron curves, with the neutron reading exceptionally high apparent porosity values. Dolomites will show a similar separation to shales but usually skewed towards high densities. The gamma ray will generally be low.

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Wireline Logging

Figure 13: Lithology Identification


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Wireline Logging

Figure 14: Gamma Ray & Grain Size

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Wireline Logging Saturation Determination The resistivity logs are used to identify potential hydrocarbon bearing zones as long as the rock has porosity and permeability. Porous, water saturated, sediments will tend to have low resistivities while hydrocarbon bearing formations will have higher resistivities. To be sure it is necessary to evaluate both resistivity and porosity logs.

Water Saturated Zones When the rock is 100% water saturated, (Sw = 1), its resistivity is known as Ro. The true formation resistivity is called Rt and is estimated from the deep reading resistivity tool. When Sw = 1, Ro = Rt

Hydrocarbons When the rock contains hydrocarbons Rt increases according to hydrocarbon saturation and porosity. Ro remains the same; that is, the theoretical resistivity of the rock when 100% saturated with water, (of resistivity Rw), is Ro. Rt ≠ Ro In the early days of logging this is about as far as it got. Quantitative analysis came along in the 1940s from Mr. Archie.

Archie Formula Archie, working for Shell, developed the basic algorithms to estimate hydrocarbon saturation from resistivity and porosity.

Sw =

n

Ro ------Rt

Where: Sw=Water Saturation Ro=Formation Resistivity at Sw = 1 Rt=True Formation Resistivity n=Saturation Exponent


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Wireline Logging The saturation exponent, n, is an empiracally dervived variable. For Quick-Look Interpretation, n is normally 2. Since Ro is not measured when hydrocarbons are present it needs to be determined independently.

Ro Determination When a rock is saturated with water of resistivity Rw, the ratio of the water overall rock resistivity to the water resistivity is constant, providing the porosity remains the same: Ro F = -------Rw Therefore: Ro = FxRw Where: F=Formation Resistivity Factor

The Formation Resistivity Factor, F, relates to the porosity. Changing the type of water filling the pores does not change the overall Ro/Rw ratio providing the porosity stays the same. Archie determined a relationship for F and the porosity (φ) as follows: a F = -----mφ Where: a=Tortuosity Index m=Cementation Factor

Values of a and m vary with lithology. Median values of a are around 1 and median values of m are around 2. Sandstones generally cause reductions in a and carbonates cause significant increases in m. Values of a, m and n are computed from core analysis, offset data and other reservoir studies. If no information is

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Wireline Logging available, a default relationship can be used though this is only an approximation.

1 F = ----2φ Substituting for Ro, the working version of Archie’s formula for Sw becomes: F × Rw ----------------Rt

Sw =

Sw =

n

a × Rw----------------m φ × Rt


3-29

Wireline Logging

3-30


Coring Introduction Coring provides information about reservoir conditions and hydrocarbon reserves that may not be available during routine drilling or logging operations. Detailed porosity, permeability and hydrocarbon saturation measurements are possible from conventional cores since the samples are large enough to show most of the controlling features, apart perhaps, from macro or fracture porosity. Of secondary importance is other geological information such as detailed sedimentary and lithological evaluation, micro palaeontological work and the opportunity for uncontaminated geochemistry analysis. Two main type of coring are available: • Conventional Coring Performed at the time of drilling Provides macro samples for complete reservoir evaluation

• Sidewall Coring Performed after drilling using wireline technology Provides small samples for lithological and palaeontological evaluation

Conventional Coring Conventional coring is the most basic operation and has been routinely done in vertical wells for many years. Core is collected in a steel tube or barrel usually either 30ft, 60ft or 90ft long, giving sample diameters of between 2 inches and 5 inches. For slimhole operations cores of 1.75 inches diameter may be obtained. Conventional cores are normally cut to provide basic rock mechanics and reservoir information from formations that are easily sampled and not prone to collapse or desegregation. Where more detailed information is required, or when the formation may not be adequately recovered, specialised coring systems such as containerisation may be employed. Conventional coring is time consuming, and therefore expensive. It involves at least two round trips, changing of the BHA and slower drilling rates are achieved over the cored interval. Only those formations of special interest are cored, and even then conventional coring is usually limited to the primary and secondary reservoir targets in most operations.


4-1

Coring Because of the expense and the importance of the information required coring operations are carried out with great care and usually with the assistance of specialised personnel and equipment.

Core Point Selection The intervals chosen to be cored are determined far in advance of the drilling operations and will normally be the primary and/or secondary targets of the well. Occasionally, when drilling in new fields or areas coring points may be established and substantially modified as a result of the drilling progress or logging operations. Usually specific formations will need to be cored rather than merely drilling to particular depths and so the coring points will normally be specified by the onset of a formation top, and becomes a matter of detailed stratigraphic correlation.

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Coring

CORING DECISION SUMMARY

WELL NAME

05/28/2002

GEOLOGIST

M. Butler

DATE

12/16/2001

TIME START/ FIN

3:25

8548/-8465

CURRENT DEPTH

8560/-8477

DRILLING DATA DEPTH DRILL BREAK (mddbrt/ mtvdss) LENGTH OF BREAK

(mddbrt/ mtvdss) 12ft

ROP Pre-break (ft/hr)

25 - 35

ROP during break (ft/hr)

66 - 105

Torque Pre-break (klbs)

6-8

Torque during break (klbs)

8-9 11.3

Mud weight in (ppg)

11.3

Mud weight out (ppg)

ECD (ppg)

11.6

Estimated O/B ppg

8.7

Pit gain (bbl)

None

Controlled drilling?

Yes - using WOB

Est pore pres Pre-break

8.7

Est pore pres during break

8.7

GEOLOGY Lithology after circulating

40% Sandstone

bottoms up

60% Siltstone

Visible porosity Nature of cuttings, e.g.

Sandstone: generally loose, locally well cemented

angular, loose grains, size,

Siltstone: normal subblocky

shape

Figure 1: Coring Decision Part 1


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Coring

SHOW DESCRIPTION FLUIDS Oil/ condensate stain

Fluorescence Light brown

colour

moderate yellow

bleed

% of sample

100

colour

intensity (weak, etc.)

Moderate

wax

cut fluor colour

Blue white

live

cut speed

slow to moderate

cut colour and stain

crush cut fluor colour

Blue white

crush cut speed

solvent used

Isopropanol

crush cut colour and stain GAS Pre-break

From break

Total gas

0.35

Total gas

(0.35 b'grnd) 1.35 peak

C1

1355

C1

4314

C2

157

C2

649

C3

136

C3

975

iC4

28

iC4

108

nC4

41

nC4

421

C5

N/A

C5

N/A

H2S

0

H2S

0

CO2

N/A

CO2

N/A

Figure 2: Coring Decision Part 2

Offset Data Formation tops have been provisionally determined by the project geologists using seismic, wireline, MWD and wellsite geological data form previously drilled wells if such information is available. Mud logs, lithology logs, drilling exponents, Gamma Ray logs and Sonic logs provide the best information for detailed correlation.

4-4


Coring During Drilling As the well progresses, the mud loggers and wellsite geologists need to perform continued analysis to ensure that the core point is reached without drilling to far into the reservoir and perhaps missing vital information form the top of the sequence. Sometimes coring will begin on drilling into the potential reservoir. At other times the cap rock or seal and its contact to the reservoir needs to be evaluated which involves even more detailed study, and substantial local knowledge. Cuttings lithology evaluation, MWD analysis and wireline log correlation provide the basic wellsite evaluation tools, in conjunction with similar offset data. As the reservoir is approached, ROP (rate of penetration) becomes the single most important tool since this will usually indicate drilling through the cap into the reservoir section. The importance of ROP is that it provides instantaneous information about rock strength and drillability when minutes or even seconds can be important. For example, if the ROP increases from 15m/hr to 30m/hr, 0.5 metres will be drilled every minute. If this drilling break is not picked up for two or three minutes a substantial part of the top of the reservoir may not be cored.

Confirmation of the core point The decision to stop drilling and take the core is critical and can lead to delay and expense if the wrong decisions are made. The well prognosis should give clear indications of the exact procedures to be followed as the core point approaches. Specifically the exact criteria for coring needs to be clearly documented to avoid confusion and costly mistakes. This may take a number of forms, for example: • Begin coring when the “X” formation is drilled into • Begin coring at “X” metres TVD (True Vertical Depth) • Begin coring in the top of the “X” formation providing the lithology is sandstone • Begin coring in the top of the “X” formation providing there are positive hydrocarbon shows and suitable gas ratio analysis Selection of the core point from hydrocarbon show evaluation and lithological confirmation obviously requires the sample from the drilling break to be circulated to surface which is time consuming, but necessary to avoid error. It may also be necessary to drill a few metres of the new formation to establish beyond doubt that it is the reservoir section and not just a small stringer above the main zone.


4-5

Coring When all the criteria are met coring can begin. The actual decisions are normally made by operations personnel in the oil company office following discussion with wellsite geologists and supervisors. In the event of poor communications between the wellsite and office then the onus will fall on the wellsite staff to make the decisions. In this case it is vital to clarify oil and gas show characteristics in terms of fluorescence and cut tests, gas ratio analysis and evaluation of drilling parameters such as ROP in order that the correct decisions can be made and substantiated.

Figure 3: Core Handling

Coring Procedures The basic coring procedures, equipment and requirements will have been decided long beforehand and should be available at the wellsite in the drilling and formation evaluation prognosis. However local conditions may require modification to the original plans and these should be discussed as appropriate but

4-6


Coring with due regard to allowing enough time for replacement equipment or supplies to be shipped to the wellsite if required. Specifically: • All items of rig and coring equipment should be available and checked • Drilling fluid properties should be optimised • The borehole should be cleaned and stabilised before coring • Geological information should be updated such as: Hardness and abrasiveness of the formation Consolidation Fractures Hole and formation pressure problems

Coring Equipment The core barrel and associated equipment is normally provided by a specialised coring contractor who will also provide experienced personnel to help set up and run the equipment and assist the driller in cutting the core. A standard core barrel configuration will comprise the following: Core Barrel Conventional Core Barrels consist of two main parts and can provide cores from 1.75 - 5.25 inches in diameter. Outer and inner core barrels are connected together to provide different length cores to be cut as required. Outer Barrel

Large diameter outer tubes provide stiffness and protection for the core. Stabilisers can be attached if required. The outer tube allows drilling fluid to be circulated with the risk of washing away the core and also allows the drillstring to be rotated, again without disturbing the core. Inner Barrel

Steel inner barrels are manufactured to very strict tolerances and are thoroughly checked at the wellsite to ensure that there are no restrictions or her impediments. All the core is collected in the inner barrel which is removed from the outer sleeve for core recovery. Swivel


4-7

Coring The swivel assembly allows rotation of the drillstring without disturbing the core. Safety Joint

All core barrels are equipped with a safety joint to allow recovery of the inner core barrel and core should the outer core barrel become stuck. It also allows the barrel to be prepared more quickly for the next run and reduces maintenance costs.

Figure 4: Core Barrel

4-8


Coring Pressure Relief Plug

This is necessary to: • Circulate out inner barrel fill following running into the hole • Enable circulation through the inner barrel when large amounts of fill are encountered. Once the barrel is clean a drop-ball is run to prevent circulation through the inner barrel during coring. Drilling fluid is vented via the drop-ball valve when core enters the inner barrel. Core Heads

The core is cut by using a regular drilling bit equipped with a large diameter hole through the centre to allow the core to pass into the inner core barrel. Whilst roller cone bits are use it is more common to use a diamond headed, fixed cutter bit to cut the core. Diamond bits give a smoother driller response and generally lead to better core recovery. Natural diamond bits are now being replaced by PDC bits which provide faster coring times without sacrificing recovery. Core Catcher

The core catcher is located between the core head and the inner core barrel. Its purpose is to prevent the core slipping out of the inner barrel after it has been cut. The core catcher consists of tungsten carbide slips and spring loaded dogs to ensure positive containment of the core. Variations can be made to cope with unconsolidated formations or when containerised sleeves are used.

Containerised Coring Over the last few years most operators have utilised containerised coring to enhance their coring operations. Containerising developed to help ensure maximum recovery of unconsolidated formations but has developed to include most operations. The process provides additional benefits such as:

• Reduced coefficient of friction between core and inner barrel • Decreased exposure of core to the atmosphere • Reduction of induced fracturing of the core • Increased core security


4-9

Coring • The containerised core can be cut to length and shipped directly for analysis

Figure 5: Core Bit

4-10


Coring

Figure 6: Core Catcher Aluminium Inner Tubes The aluminium inner tube replaces the existing steel inner barrel. Useful in high temperature applications the tubes come in lengths of 30ft and can be connected together to provide 120ft of core. The filled tube can be cut to length, capped and shipped. Fibreglass Inner Tubes Fibreglass tubes also come in 30ft connectable lengths to contain difficult samples. They are not suitable for high temperature applications of more than 250° F.


4-11

Coring Plastic Liners Plastic liners ensure recovery of soft, friable and unconsolidated formations, and can recover up to 60ft at a time. They are unsuitable for temperatures above 140° F.

Figure 7: Containerised Core Sleeves

Coring Procedures Careful attention to detail and operational parameters is required in order to ensure a successful coring operation. Drilling should proceed relatively slowly and evenly with slightly reduced WOB and Pump Pressure.

4-12


Coring Junk On the last bit run prior to coring a junk sub should be run in order to collect small bits and pieces from the borehole. Junk in the hole will cause damage to the core head and reduce the chances of cutting and recovering a complete core. Core Head Selection This is made with reference to the formation strength and abrasiveness and to the bottom hole pattern established by the previous bit run BHA Design Sufficient drill collars are required to produced the necessary WOB as with routine drilling., together with adequate stabilization. Circulation Circulation rates need to be enough to clean the hole of cuttings but not too high to lift the core head off bottom and restrict drilling. With PDC core heads this limit of Hydraulic Horsepower per square inch will be enforced anyway. Too high circulation rates may also tend to wash away the core as it enters the inner barrel area. This can be minimised by reducing flow rates and using modern lowinvasion core heads. Lost Circulation Material (LCM) Lost Circulation Material can be used with caution in most coring operations but is not recommended. Other Drilling Parameters Other parameters such as WOB, RPM and Torque will be established according to the equipment configuration and the nature of the formation. Remember though, that the primary objective is t cut ad recover the desired interval of core. WOB is normally kept low until the core head has established a bottom hole pattern and the first stabiliser has entered the new hole. It is then increased until optimum performance is reached. Preparation for Coring With the bit off bottom mud is circulated through the tool to ensure that there are no restrictions to flow or that fill has not entered the barrel. Once this has been established and the hole has been circulated for 15 minutes or so the pressure relief ball can be dropped. When the ball has seated a note is made of the offbottom pump pressure.


4-13

Coring Cutting the Core Drilling proceeds in controlled manner with WOB and Pump pressure being regulated to achieve optimum performance. Sudden changes to any of the coring parameters could damage the core head or the core itself. The mud logging crew will continue to collect cuttings samples during the cutting of the core as back up information should recovery be incomplete. The quality of these samples is much reduced however since circulation rates are lower, reducing effective hole cleaning and only an annulus around the core head is providing fresh cuttings material. There is though, still the same volume of cavings recycled material and LCM as during normal drilling so that the amount of effective debris is increased. Coring continues until the core barrel is full or becomes jammed. Careful monitoring of depth and ROP should indicate when the barrel is becoming full as ROP will decrease sharply at this stage. The core head should be allowed to drill off the WOB to ensure a clean cut at the end of the core. Core Recovery The type of core being cut will determine the exact handling and recovery procedures that will be followed, along with operator requirements. Most conventional cores are recovered on the rig floor by removing the entire inner core barrel and allowing the core to slide out to be collected in 1m (3ft) core boxes. Wireline retrievable slim-hole cores are also handled in this manner. Containerised core is removed from the outer barrel, cut to length, capped and shipped to town with little or no rig site processing. Conventional Core recovery It is the responsibility of the wellsite geologist to ensure that the core is recovered, processed and evaluated according the operator requirements. In most cases they will recover the core with the assistance of mudlogging personnel. prior to the coring operation it is necessary to ensure that sufficient stocks of consumables such as wooden core boxes, marker pens, rags, wrapping and packaging materials are available for the total amount of core that is to be cut. During the cutting of the core the mudloggers will have gathered all the above material together and labelled the required number of catching boxes with core number, box number and top and bottom markings. The core barrel is retrieved to the surface and the inner barrel removed. The driller holds the inner barrel on the elevators and the core catcher removed. The core tongs are attached by the core hand and the inner barrel is slowly raised whilst the tongs are relaxed. this allows the barrel to slide over the core and expose it on the rig floor. Once 1m (3ft) of core has been exposed it must be broken off in order to fit into the recovery boxes.

4-14


Coring Often the core will emerge broken pieces which need to be monitored to ensure their correct orientation when placed in the boxes.

Figure 8: Inner Core Barrel Removal Caution It is important to remember not to reach underneath the core barrel when breaking or collecting the core as any uncontrolled slippage could cause serious damage. Recovery of the core should proceed at a rate comfortable for the wellsite geologist or mudlogger catching the samples. Each broken piece should be correctly oriented prior to placement in the box and rubble should be collected and paced in its appropriate place. The very bottom of the core is normally placed in the bottom of box #1, and the last piece of core will be at the top of box #?


4-15

Coring It should be remembered that the very bottom piece of core may still be attached to the core catcher if it was jammed in. This is potentially the most important piece at the moment since the next rig operation may be dependent on what the bottom section represents. If it is still reservoir lithology with oil shows a decision to continue coring may be made, Alternatively if it is shale or reservoir rock without oil shows normal drilling may be resumed.

Figure 9: Conventional Core Extraction Processing the Core Conventional cores need to be cleaned, measured, described and evaluated for oil and gas shows, wrapped, re-boxed and shipped from the rig. All of this work is the responsibility of the wellsite geologist and has to be performed in a speedy and accurate manner. With long coring runs using 90ft or 120 ft barrels the complete processing of one core can take many hours by which time the next core may be arriving at the rig floor. The core needs to be worked on in a well lit, dry area with plenty of space to allow the core to be removed from its catching boxes, laid out and repackaged. The core should never be washed to avoid damaging its saturation and other reservoir characteristics, but should be wiped clean with rags to remove the mud and allow its lithological and sedimentary features to be described. Prior to description the core should be accurately measured and some attempt made to fit broken pieces together. Orientation marks, normally made by scribing red and black lines along the length of the core need to be mace very

4-16


Coring quickly so that each core piece can be oriented following removal from the original catching boxes.

Figure 10: Core catching Boxes An accurate measurement is required to determine the amount of core recovery and to correlate the core with depth. At this stage any missing core is deemed to have been lost by falling out of the bottom of the barrel during recovery and all depth measurements proceed from the top of the core. Detailed core analysis may reveal a different story but this is not applicable at the wellsite. Before wrapping, the core should be fully described and particular attention paid to larger scale sedimentary features that are not always apparent in drill cuttings. Samples should be taken at the regular sampling interval and extra samples where oil shows are apparent. These should be processed in the normal manner in the logging unit. Other larger samples may need to be removed from the main body of the core and shipped separately for other processing such as core analysis, or geochemistry. The bulk of the core is wrapped in a variety of media in order to seal and protect it before being placed in clean boxes for shipment. Aluminium foil, Saran wrap, polythene tubing and wax are all used for this process.


4-17

Coring Once packed for shipment, complete details should be recorded and packing lists kept, plus details of shipping procedures. All this information should also be communicated to the local operations office prior to shipment.

Figure 11: Core Marking

Other Specialised Applications High Angle and Horizontal Coring Specially designed core barrels are available for drilling high angle and horizontal wells. They provide extra stabilization and bearing adjustment to ensure optimum performance. They can also include integral EMS surveying systems for accurate orientation when using a 3-knife scribing system. Oriented Coring gathers comprehensive and reliable information on fracture direction, the dip and strike of beds, and the direction of stresses. When a core is oriented, hole azimuth and inclination are recorded along with the directional orientation of a reference mark on the core itself. Simple equipment and proce-

4-18


Coring dures make this service economical and versatile with both conventional and advanced technology coring systems. The core barrels are usually driven by a Mach 1 Positive Displacement Motor system and incorporates a dropball sub that can be run after circulation to remove fill.

Pressurised Core Barrel Pressurised Core Barrels can be run to maintain bottom hole conditions and provide more accurate saturation and mechanical property data. These systems may use a non-invading gel to maintain core sample quality while preventing gas expansion and fluid loss. At surface the inner tubes are frozen for transportation using dry ice to immobilise fluids and gases while retaining bottom hole pressure.

Reduced Fluid Invasion The key to preventing drilling fluid from invading high permeability core is to protect the filter cake that builds up around the core during the coring process. If this can remain undisturbed than further flushing is prevented. Special core heads allow the core to move immediately into the inner barrel by removing internal cutters and gauge protection, and by ensuring that jet nozzles point away from the incoming core.

Gel Coring Gel coring provides a means of protecting the core from the invasive drilling fluid by encapsulating it with a polypropylene glycol compound, and also protects the core during handling, processing and transportation. The gel is preloaded into the core barrel before delivery and isolated from the drilling fluid during the trip into the hole. It is displaced by the core which forces it around the inner barrel annulus as the core is cut. Any gel that does not adhere to the core is ejected to the annulus and displaced by the drilling fluid.


4-19

Coring

Figure 12: Gel Coring

Full Closure Core Barrels When the reservoir rock is poorly cemented or unconsolidated additional measures must be taken to ensure that the core is not lost through the core catcher. Rather than the finger type catcher, such rocks need a full closure catcher in order to retain the material.

4-20


Coring

Figure 13: Full closure core barrel

Wellsite Core Evaluation Some companies provide wellsite core evaluation equipment in order t o transportation costs in remote locations. Core cutting, slabbing, plugging and preservation equipment is available together with gamma ray, UV-light photography, porosity and permeability measurements.

Sidewall Cores Sidewall cores, or CSTs (Core Sample Taker), provide a means of sampling the formation when a conventional core was not taken during routine drilling. The gun, which can hold up to 30 bullets, is conveyed into the hole by wireline. Each bullet can be individually fired at a specific depth in order to obtain a sample from a specific geological horizon. Depths are chosen by surface correlation and a Gamma Ray tool is run for confirmation. The bullets are attached to the gun by wire fasteners and fired by an electrically triggered explosive charge. The bullet is pulled from the formation as the tool is raised together with its core plug; it is held by the wire fasteners as the tool is pulled to the surface. Different length fasteners are available to allow for varia-


4-21

Coring tions in hole size and there are different explosive charges and bullet designs which are also Operator choosable. The main purpose of sidewall cores is to obtain geological samples from a known and specific geological horizon for lithological and bio-stratigraphical confirmation. Since the core is obtained by impact it can damage weak reservoir rocks and render estimations of porosity, permeability and saturation less than accurate. The Wireline Logging personnel set up the tool and retrieve the core samples at the end of the run. The samples are normally placed in small glass bottles with an identification label and passed to the Wellsite Geologist for examination and dispatch. The Wellsite Geologist is normally required to make brief sample descriptions, including oil show evaluations before the samples are shipped from the rig.

4-22


Coring

Figure 14: Sidewall Coring Gun


4-23

Coring

Figure 15: Sidewall Core recovery

Rotary Sidewall Coring Small core plugs can be obtained by rotary sidewall coring operations in order to obtain samples after drilling or in the event of problems with conventional coring. Samples are less damaged than those from wireline CSTs and are suitable for reservoir characterisation as well as lithology studies.

4-24


Coring

Figure 16: Rotary Sidewall Core


4-25

Coring Drilling Considerations The purpose of coring is to acquire a representative sample of the formation being cored. Alteration of the rock properties and fluids contained within the formation should be avoided as far as is possible if representative measurements and information is to be gleaned from the core. Any coring operation should approach fastest possible coring at highest possible recovery. Prior to coring make sure to clean and ream the hole properly when POOH prior to start coring. Core with minimum overbalance. Consider high torque motor if string torque/off bottom torque is high. The degree of drilling fluid invasion during coring will in general be influenced by:• Mud overbalance • Compressibility of pore fluids • Time of exposure • Drilling fluid filter loss control properties • (Relative) permeability of the rock.

Mud invasion can be minimised by increased coring rate, reduced filtration area, increased bridging solids in the drilling fluid and reduced contact time with the gauge cutters (Rathmell et al. (1990)). The low invasion coring system suggested by Tibbits et al. (1990) combines application of specialised equipment (specially designed core head, inner tube pilot shoe) with proper coring parameters and a low spurt loss fluid. Eaton et al. (1991) define low invasion technology as a combination of advanced core bit technology and modified coring techniques to produce cores with no drilling fluid filtrate invasion over two-thirds of the core’s cross section. Minimisation of core invasion is achieved by (Eaton et al. (1991)): • Reducing the number of cutters over the entire bit • Using a parabolic bit design • Using a low fluid loss drilling fluid • Reducing the number of gage cutters • Eliminating all throat diamonds

Low invasion core heads should be preferred to other core heads. Also consider the use of Gel to limit invasion of the core. Alteration of the core is not restricted

4-26


Coring to the downhole coring process, but also to retrieving the core, (e.g. tripping speed), laying down the core and processing the core for transport to the lab.

Jamming off It is quite common for cores to 'jam off' before the core barrel is full, especially in hard, fractured, formations. In friable, porous or fractured formations it may not affect the R.O.P, and the only sign of jamming may be a slight increase in torque. In medium to hard formations ROP and torque may decrease. If jam-off of the core is suspected, it is recommended that coring should cease and that the core is recovered before continuing the coring program. This will minimise the possibility of a gap in the cored sequence in softer formations, and reduce the potential for damage to the core already in the barrel. A possible exception is in the event that no further cores are planned for the interval. In this circumstance there may be benefits in attempting to restart the core, since there exists the opportunity of recovering core which would not otherwise be cut. Jamming off can also occur due to the inability of the heave compensation systems of semi subs and drillships to adequately compensate during rough weather. In such circumstances conditions may be fit for drilling but not for coring. Serious considerations should be given to telescopic core systems when coring from floating platforms.

Pulling Out When a core is brought up to the surface, pressure and temperature conditions are altered considerably. This can cause: • Elastic/anelastic expansion of the rock matrix, causing cracks or fissures • Expansion of fluids with high compressibility and dissolution of gas. • Matrix expansion and capillary suction in rocks with low compressibility fluids This may lead to: • Changes in pore geometry, porosity and permeability • Wettability alterations • Dissolution of gas and capillary effects Loss of interstitial water • Salt precipitation • Damage to clay fabric • Continued filtrate invasion.


4-27

Coring Pulling out of the hole with a core barrel should be accomplished as quickly as possible, however it is important that the driller and rig crew take more than normal care to ensure that jolts and jarring of the drillstring are avoided. Soft, friable cores and long, heavy cores in hard, dense formations are particularly susceptible to damage or loss by careless tripping. Expanding pore fluids that are unable to escape from the core during trip-out may induce whole core dilation, and/or axial vertical fracturing. This damage mechanism is most common in poorly consolidated sediments containing viscous crude, or core that has suffered a high degree of mud filtrate invasion. Field studies have indicated that reducing the trip-out rate yields core of improved quality, while laboratory studies have shown that the majority of core dilation occurs over the latter stages of the trip. Therefore, reducing the trip rate as the core nears the surface is likely to minimise core dilation and yield core of improved quality. Fragile core material can be prone to structural damage resulting from gas expansion during retrieval. During trip-out, if pore fluid retention causes pore pressure to exceed surrounding mud pressure such that the tensile strength of the core is overcome, then disaggregation or expansion of the core will occur. This type of damage can often be identified if ‘overgauge’ core is recovered. Reducing the core retrieval speed over the latter stages of the trip can yield core of improved structural quality. Rapid tripping also increases the gas drive effect on core fluid saturation, and this may reduce the accuracy of the oil saturation results. Pressure depletion and temperature reduction during core surfacing also afford opportunities for wettability alteration, controlled tripping may help reduce this effect. If non-hydrocarbon bearing dense zones only is cored, then the core may be tripped at near the normal controlled rate 1-1.5 minutes/stand’ for the complete trip. In deep / high pressure wells, or areas where hydrogen sulphide gas is a known hazard, it may be considered advisable to stop pulling out 500m below rotary. The core is then allowed to 'de-pressurise' for a period of time, depending on its size, porosity and permeability. About 30mins is usual. However, in most cases the core will have ample time to de-gas on its way out of the hole. RFC policy requires the following tripping speeds: • Normal tripping to 900 m • 900 m to 450 m : 3 minutes per stand • 450 m to surface : 6 minutes per stand

4-28


Coring Security DBS recommended the following tripping speeds: • Reducing POOH rate speed last 350 m • Up to 350m: 1,0 min per stand • 350-100m : 2,5 min per stand • 100-surface ; 5,0 min per stand

Use the drilling brake and the slips GENTLY when POOH to prevent core collapse or lost core.

Circulating Bottoms Up In contrast to most other drilling situations, circulating bottoms up after coring should be avoided. The usual procedure after terminating a core run is to pull one stand off bottom, check for flow, and then pullout. Circulating carries with it the risk of sucking the core from the barrel. However, it is recognised that unforeseen, unstable well conditions may necessitate circulation, and because of this possibility it is recommended that a circulating sub is run above the core barrel to allow circulation if required.

HTHP Wells In HTHP wells the expansion of gas in the core as it is pulled to the surface can create a potentially dangerous situation. Documented cases have demonstrated that the pressure of gas trapped in a core barrel or sleeve at surface can be sufficient to eject the core, and propel it across the width of a rig pipe deck with considerable force. To reduce the risk of this happening, core inner barrels are now available with pressure relief valves at intervals along the length of the barrel, and these should be used whenever possible in HTHP situations. Fluted inner barrels are also a solution to this issue. Alternatively pressure relief holes may be drilled in the barrel after recovery, but this operation will present its own hazards which must be addressed at the wellsite. Sensible precautions should be taken with regard to the area used to lay down the barrel, and the presence of any unnecessary personnel. Personnel should be briefed on the potential hazards, and should avoid placing themselves in the danger zones around the open ends of the barrel. In some situations the option of freezing the core in its sleeve may be available. This is achieved using dry ice, before cutting the core into 1metre lengths.

Core Handling On Rig Floor The aim is to remove the core inner barrel and core in 9m lengths from drill floor to processing area without core damage, and in minimum time to minimise cost.


4-29

Coring Core laydown is not a routine activity. The core hand will lead a briefing and discussion with the rig crew involved to ensure that safe and effective procedures are used before beginning core laydown. Company drilling representative, wellsite geologist, corehand and core specialist and other key personnel should also be present to highlight importance of safe effective core handling, and to promote good teamwork. The core barrel will be checked for gas at surface before breakdown. Gentle core handling is essential - the rig crew input to a safe and successful coring operation is critical at this point The inner barrels must be separated on the rig floor. The rig floor breakdown of the core barrel, laydown of the core inner barrel, and breaking of the catcher will be led by the corehand. Any misalignment of the inner tube during inner tube separation and application of shearboot may result in dropping the core on the drill floor. This activity must be conducted with great care. When breaking the cores into 9m lengths a hydraulic cutting device or shear plate assembly should be used to prevent damage to the core. It has been shown by visual and X-ray CT examination that the use of a hammer damages core up to 1 m from the joint. After removal from the core barrel, the inner barrel must be transferred to the processing area, which provides a safe environment for the core processing team, and minimises disruption to drilling operations. This must be done without allowing the inner barrel to bend. Core cradles (or core sock) are used for this purpose. Note: when a "CORE SOCK" is employed attention MUST be given to preventing movement of the core within the core sock. An unsecured core can suffer damage during movement from the rig floor to the designated core processing area. The core cradle is suspended vertically in the derrick alongside the 9m inner barrel section and is secured to the inner barrel with straps. When the inner barrel is secured in the cradle, the tugger line is connected to the top of the cradle and the air-hoist line removed from the inner barrel pick-up sub. Normal precautions for heavy lifting must be followed - particular care is required if rough weather results insubstantial rig movement. Various techniques are suitable for the successful laydown of core cradles. The rig crane may be used to directly transfer the cradle / inner barrel from the drill floor to the core processing area, or the cradle can be lowered gently down the pipe skid and onto the catwalk, and then transferred by crane.

Awareness Of Gas In The Core There is likely to be a constant bleed of mud and gas from the core. Prior to pulling the coring BHA above the BOP the moonpool area should be cleared and

4-30


Coring access to the rig floor restricted to essential personnel only. Be aware of the prevailing wind direction and be particularly cautious in calm still conditions. The rig crew must be made aware of the potential H2S presence in the reservoir and hence the core. Checks for H2S by a qualified person wearing breathing apparatus using a suitable H2S detector must be made during core retrieval and when each drill collar connection is broken. If H2S is detected at this time consideration should be given to running the core barrel back into the hole to below the BOP. Circulation can then be commenced to help dissipate the gas.-It will be necessary, under these circumstances for all personnel on the rig floor and those involved in core handling to don breathing apparatus while the inner core barrels are laid out and until declared safe by the qualified person using the detector. When the last drill collar is broken off the core barrel, heavy gas maybe released. The core will be laid out in 30 ft lengths using the inner core barrel handling cradle. When separating the inner tubes, check for indications of confined pressure. If connections bubble with gas, cease backing out the connection until the bubbling has diminished. The upper shoe and core catcher are generally broken out on the catwalk. Gas may be confined and precautions must be taken to prevent personnel from being around the end of the inner tube.

Core Processing Core cutting requires a high-powered air saw - this must only be used by qualified operators, with appropriate personal protective equipment(gloves, goggles, hearing protection and dust mask). All non-essential staff should stand clear. Core processing is a non-routine activity. Pre-job briefings will be given to any staff who will temporarily assist (e.g. rig crew, mudloggers). Air hoses will be routed to the core processing area and must be properly located, connected and secured. All core processing activities must be discussed with and approved by the drilling representative before work begins. Proper permits must be obtained for any specialised procedures and equipment. Roles and Responsibilities: Core mark-up to be performed by the RFC wellsite geologist with assistance from the core specialist. • Core GR to be run by the core hand. • Core cutting will be performed by the core hand.


4-31

Coring The coring contractor to supply personal safety equipment and coremark-up consumables. Rags for cleaning inner barrel. Pens or paint sticks that will indelibly mark inner barrel under rigsite conditions. • Core GR • Good quality measuring tape at least 10m long. Core Cutting Saw with Diamond cutting blade will be used,cutting wax to be applied onto the saw blade to provide adequate cooling and lubricating. Water must NEVER be used. End Caps, Clips and Tools. Coring company to supply good quality pneumatic and battery driven “screwdriver” to secure caps& clips. 2 x caps & 2 clips required per cut section. Sealing sample bags and sampling equipment (spoon for sof sandstone and hammer and screwdriver or small chisel for hard sections). Paint scraper for cleaning core faces for inspection. Core Box's Wax bath for core preservation at the wellsite. (Can be supplied by the core analysis contractor). Only essential core processing staff will be allowed in the area.

Conventional Core Barrel After removal from the core barrel the core(s) should be wiped with a rag and immediately placed in core boxes without washing. Working from the shallowest (top) part to the deepest (bottom) part, mark the core with two (2) parallel lines, the right line in red and the left line in black. It is imperative to face the top of the core when marking it with parallel lines as described above. Otherwise, the marking will be exactly opposite of what is wanted and this may subsequently cause considerable confusion. This conventional marking will facilitate reorientation of any pieces should they become misplaced. Mark depths on the core each 0.5m starting from the top of the core. Indicate depths with a line extending around as much of the circumference of the core as possible, and write the depth clearly beneath the line. Where the core is rubbleised, label any bags with the depth interval contained. In the case of length of core recovered being less than the interval cored, always assume that the 'lost' portion is missing from the base of the core. If there is good evidence that it is missing from elsewhere in the core, note this on the core report and on the wellsite core log. Numbering of core boxes should begin from the top of the core. Bottom (B) and top (T) of the core is to be clearly marked on each box. Inside the lid mark the individual depth interval of each core box. The outsides of the boxes should be marked with the company name, well number, core number and box number. The whole core should be tightly wrapped in a none reactive plastic wrap e.g. Seran Wrap or pure polyethylene, and then wrapped in aluminium foil. Note,

4-32


Coring Seran Wrap is recommended since cling film products may react with hydrocarbons. From sands preserve one 15 to 25 centimetre long sample every second meter, as above, and seal the sample in plastic tubing/protec core, using a heat sealing machine (provided by the core handling contractor). In hydrocarbon bearing zones preserve samples every meter. Alternatively, preservation of the chosen pieces may be done by wrapping the core piece in Seran Wrap, then aluminium foil and finally dipping it in a wax bath to seal. In addition to marking the depth interval on the sample, the exterior wrapping material should be labelled with the top and bottom depths, and an arrow should point to the upward end of the section. A cardboard label with details of the core number, well, company, date, and depth interval should be sealed in with waxed samples or placed in a plastic bag inside the protective tubing. Normally preserved samples will be replaced in their correct position with the rest of the core in the core boxes.

Fiberglas or Aluminium Core Sleeve On retrieval of the core sleeve, it is to be cleaned and marked with two parallel lines, red to the right, black to the left as described above for conventional cores. After measuring, the mudlogging contractor and/ora core hand can cut the core into 3' or 1 m lengths (according to size of boxes) and samples taken at the end of each length of core. Lithology from butt ends of each core is to be described. Each length of core sleeve will be capped and clamped. Subsequently, the cores are to be placed inside wooden boxes and properly padded for protection. The depth interval and box number must be clearly marked on the outside and inside of the box. Top and bottom depth labels are to be marked on the fibreglass sleeve of each individual section. An option exists not to cut the core at the wellsite. When this is exercised the barrel is marked as noted above and the ends capped. A sample can be taken from the bottom of the barrel first. The inner barrel is then loaded into a cradle and loaded onto a boat for transport to town. It may be desirable to preserve pieces of the core at the wellsite. If so the procedure outlined in the last paragraph of Conventional Coring Procedures should be followed. Cores can be prevented from drying out by either injecting the annulus of the core sleeve with epoxy resin or foam. Core chips (approx. 50 g) taken from the cores are to be sent to Shore Base for subsequent biostratigraphic analysis, if appropriate. After sealing, labelling and


4-33

Coring boxing, each individual core is to be sent to the core laboratory as fast as possible. It should be noted that the wellsite geologist and the mud loggers are responsible for the handling and sealing of all cores. The wellsite geologist will notify each shipment by telefax or email to the Shore base office, attention Ops. Geologist.

Aluminium Half Moon Inner Barrels The benefit of using a half moon barrel is that the whole core can be viewed without or before cutting into 1 m lengths. Once the inner barrel is laid out in the designated core handling work area the aluminium inner sleeve can be removed from the iron inner barrel. The wellsite geologist will find core top, and confirm core recovery. The wellsite geologist will then lead core mark up. It is usually best to subsequently mark cut lines and then initially depth mark the core, to avoid confusion. The top section of the Half Moon tube can if required at this point be lifted off for a quick geological description, it must be placed back and secured with clips before sawing process starts. After removing the top half of the tube a quick wipe of the core surface with clean rags can allow an overview of core recovery, sand shale net to gross and the location of hydrocarbons. The core can be digitally photographed, marked with master orientation lines (red to right, black to left), measured, marked up and very briefly described before replacing the sleeve cover. The core can then be returned to the inner barrel, loaded into a cradle and shipped to shore without cutting. Alternatively, clamps can be put on the inner barrel and the core cut into 1 m sections, loaded into core boxes and shipped to town. When the core is cut into meter lengths the RFC wellsite geologist can take a small chip sample from each top face for subsequent detailed description. End caps and clips will be applied to protect the core faces and prevent dehydration.

Core Handling It is wise to mark the inner barrel or liner as described above, before shipping to town. It is also wise to minimise core exposure time to the air to prevent drying out. The quicker the core is handled the better. It is essential that the core is not allowed to remain lying around on board the rig or onboard a boat for days on end. Cores that are not preserved deteriorate so it is very important to get the cores to the laboratory as soon as possible.

4-34


2

Shows

Good

V. Good

None

None

Depth

8703.5

8733.45

8763.75

8795.65

None

None

V. Strong

Strong

Odour

8675 – 8798ft Cored Interval Well Name: 28/05/02

Core Number

CORING REPORT 123ft

5 1/4

None

None

Light brown

Light brown

Stain

None

None

Uniform bright yellow orange


Natural Fluor

None

None

Fast streaming blue white


Cut Fluor

Silty Claystone

Silty Claystone with Sandstone Stringers

Coarse Sandstone

Coarse Sandstone

Coring Inc.

8675.0 – 8795.65ft

Calleva Sand

Recovery

Recovered

Date

98.1%

120.65ft

20/12/01

Colourless, light brown (oil stain), rarely dusky yellow green, locally white, moderately to very friable, crumbly, predominantly quartz, locally quartzite lithoclasts, rare carbonaceous fragments, medium to coarse, locally very coarse, subrounded, locally subplaty, locally subelongate, poorly sorted, very poorly cemented with calcite. 5-10% visible intergranular porosity, strong hydrocarbon odour, slow oil seepage, uniform bright yellow orange fluorescence, fast streaming blue white cut, instantaneous blue white crush cut, light brown residual ring. Colourless, light brown (oil stain), rarely dusky yellow green, locally white, moderately to very friable, crumbly, predominantly quartz, locally quartzite lithoclasts, rare carbonaceous fragments, medium to coarse, locally very coarse, subrounded, locally subplaty, locally subelongate, poorly sorted, very poorly cemented with calcite. 5-10% visible intergranular porosity, very strong hydrocarbon odour, slow oil seepage, uniform bright yellow orange fluorescence, fast streaming blue white cut, instantaneous blue white crush cut, light brown residual ring. Silty Claystone with interbedded calcareous Sandstone with slumped margins Silty Claystone: Olive black to green black, hard, fractured, abundant slickensides, blocky, locally micaceous, locally pyritic, slickenside fractures filled with fibrous and crystalline calcite, also traces of oil, locally there are more massive calcite veins, locally moderately calcareous. Sandstone: White, colourless, hard, none friable, blocky to subangular, fine, quartz, subangular to subrounded, subspherical, very well cemented with calcite, locally streaked with pyrite veins. Shows slumping structures into Claystone below. Medium to dark grey black, locally green black, hard, subfissile, micaceous, locally slightly pyritic, abundant carbonaceous macro fossils fragments, none calcareous, locally micro lenticular calcite veins.

Core Description

Coring Contractor

Rec. Interval

Formation

Lithology

Described by: Jamie Cureton

Total Cut

Diameter

CORELOG WELL INFORMATION

EQUIPMENT

Company

Core BBL Type & NO:

HT 60

Core no:

PERFORMANCE 2

Contractor

Core BBL Size

180'X 9 1/2" X 5 1/4"

Interval Cored-FFinish

8798

Ft

Rig Name

I.T. Type

JAMBUSTER

8,675.0

Ft

Well No

Stab. Size

12 7/32"

Amount Cored

123.0

Ft

Field

L. Shoe & Catcher

PILOT SHOE & SPRING

Core Recovery

120.7

Ft

Area

Bit Style & Size

RC 478 C3 12 1/4" X 5 1/4"

% Recovery

98%

%

Hole Temp

Bit ser #

322935

Coring Hours

30.70

Hrs.

Hole Size

TFA

1.06

ROP

4.01

Ft/hr

Hole Angle

IADC Dull Grade-Start

0/0/NO/A/X/IN/PN/PR

Reaming

WASHED/REAMED LAST STAND

Start

Formation

IADC Dull Grade- Finish 3/7/WT/N&T/X/IN/CT/PR

Service Engineer Name

TOM/JOHN

Lithology

SPP on/off bottom

725--1000

Date

18/19-12/01

Liner Size

6 1/2"

Remarks

Mud Type

K/CL

WT.PPG

11.3

WL

SPM 2%

% Solids

Tr

6.8

GPM LCM

200--400

n/a

OPERATING PARAMETERS

8,675

8,675

8,675

8,680

8,680

8,680

8,680

8,685

8,685

8,685

8,685

8,690

8,690

8,690

8,690

8,695

8,695

8,695

8,695

8,700

8,700

8,700

8,700

8,705

8,705

8,705

8,705

8,710

8,710

8,710

8,710

8,715

8,715

8,715

8,715

8,720

8,720

8,720

8,720

8,725

8,725

8,725

8,725

8,730

8,730

8,730

8,730

8,735

8,735

8,735

8,735

8,740

8,740

8,740

8,740

8,740

8,745

8,745

8,745

8,745

8,745

8,750

8,750

8,750

8,750

8,750

8,755

8,755

8,755

8,755

8,755

8,760

8,760

8,760

8,760

8,760

8,765

8,765

8,765

8,765

8,765

8,770

8,770

8,770

8,770

8,770

8,775

8,775

8,775

8,775

8,775

8,780

8,780

8,780

8,780

8,780

8,785

8,785

8,785

8,785

8,785

8,790

8,790

8,790

8,790

8,790

8,795

8,795

8,795

8,795

8,795

8,680 8,685 8,690 8,695 8,700 8,705 8,710 8,715 8,720 8,725 8,730 8,735

Prepared By Billy Roy

120

100

80

40

20

0

50

45

40

35

30

25

20

10 15

5

0

10

8,675

60

RPM

WOB Klbs

8

6

4

0

2

TORQUE Kft.lbs 1200

1000

800

600

0

200

70 80

50 60

30 40

10 20

0 8,675

400

PRESSURE psi

ROP Ft/hr

9125.0

9118.0

8873.9 9111.9

9106.0

9101.0 9087.0

9070.0

9050.0 8934.0

1

2

3 4

5

6 7

8

9 10

misfire 0.8

0.6

misfire 0.8

0.6

misfire 0.6

0.8

1.0

Length (ins)

good

~

~

~

~

~

~

Shows

20/06-4

Well Name:

Depth (ft)

60

Total Attempted

Core No.

8

Run Number

fairly strong hydrocarbon

~

~

~

~

~

~

Odour

light brown uniform

~

~

~

~

~

~

Stain

moderate to bright yellow gold

~

~

~

~

~

~

Natural Fluor

Described by:

Recovered

Diameter

immediate weak diffuse white, moderate bluish white blooming

~

~

~

~

~

~

Cut Fluor

very slight discolor -ation

~

~

~

~

~

~

very weak yellow brown / bright bluish white

~

~

~

~

~

~

Residue: UV / white

Coring Contractor

Empty

Cut Colour

Martin Butler

43

Formation

sandstone

shale

shale

shale

shale

shale

shale

Lithology

Hole Size

Lost Bullets

Date

12¼”

0

3rd May 2002

dark greyish orange to grey brown, unconsolidated, firm to hard, induration altered by bullet impact, very fine to dominantly fine grained transparent and occasionally translucent quartz, angular to subangular, very rarely very well rounded and frosted grains, rare moderate green glauconite and siliceous white cylindrical microfossil debris, weak calcareous cement, very good intergranular porosity

medium dark brownish grey, firm to moderately hard, moderately calcareous, generally slightly silty with frequent very fine grained mica, subfissile medium dark brownish grey, firm to moderately hard, moderately calcareous, very slightly silty and micromicaceous, traces of disseminated pyrite, subfissile to fissile

dark grey to dark brownish grey, firm, very calcareous, slightly silty and micromicaceous, subfissile medium dark brownish grey, firm, very calcareous, generally slightly silty and micromicaceous, with moderately silty laminae containing frequent very fine to fine grained muscovite, subfissile to fissile, earthy texture

dark grey, firm, slightly silty and micromicaceous, very calcareous, fissile dark grey, firm, slightly silty, very calcareous, trace mica, rare calcite healed microfractures, occasional greasy lustre, fissile

Core Description

Schlumberger

2

Kimmeridge, Calleva Sst

SIDEWALL (CST) CORE REPORT

Log Witnessing Logging Witness Job Specification a. Key Result Area • Provide expert advice on the drilling rig related to wireline logging, to ensure quality control of the measurements and to gather all relevant petrophysical data in such a way that the objectives outlined in the Drilling Programme are being met. • To supervise the acquisition of borehole seismic survey information, interpret in-field and evaluate the obtained data to ensure quality control of measurements, and or gather all relevant geophysical data. b. Performance Indicators • That the wireline logging objectives are achieved and that a detailed log of logging operations is maintained. • That the wireline logging operations are carried out in a coordinated and safe manner without any unnecessary delays. • That the petrophysical logs are reported in a timely and professional manner. • Attaining the highest possible standards in the acquisition of borehole seismic surveys through quality control. • That borehole seismic survey operations are carried out in a co-ordinated and safe manner in an optimal time frame. • That all data acquired for borehole seismic survey and site surveys is reported and transmitted for processing in a timely manner. c. Responsibilities • To ensure that all specified wireline equipment and personnel are available on the rig (and boat) with correct specification and/or certificates, to perform the service safely and efficiently. • To supervise all wireline logging operations and provide technical support and troubleshooting as required.


5-1

Log Witnessing Wireline Logging Procedures In the event that an Operator log analyst is not at the wellsite, the wellsite geologist shall supervise all logging operations. He/she will make sure that all log headings are complete and correct and instruct the mud engineer or mudlogger to have circulated mud samples ready for the logging engineer at the beginning of the logging job. Any difficulties experienced during logging, and any anomalous log responses should be noted on the "Remarks" section of the log header On arrival at the wellsite the logging engineer and the wellsite geologist should go over the mudlogs and MWD logs of the section to be logged and review the objectives of the wireline programme. The Wireline Specific Guidelines and logging parameters should also be reviewed to ensure that there are no misunderstandings regarding requirements from the job. The WL engineer will tell the geologist what he plans to do and what deliverables he intends to give. This will enable any misunderstandings to be dealt with before they cause a problem. If there are added instructions to those that appear in the DP and the DAP then the witness should provide these in written form. All tools outlined in the logging programme for the section of the well will be required to have a backup. In certain instances the backup need not necessarily be the same tool type, e.g. an RCI™/MDT™ may be backed up with a FMT™ / RFT™. Details are given in the drilling program. Verify that all necessary tools and back-ups are available on site in good time. If fluid samples are to be taken, ensure an adequate supply of containers: plastic bottles for water samples and 1 gallon metal cans for oil samples. Also ensure that a suitable measuring vessel, a gas meter and resistivity meter are on-site. Prior to the job, ensure that all tools, and their back-ups are tested on surface and any problems or faults noted and rectified. Ensure calibration checks are made and recorded prior to commencing logging, and again after each run. Attach these to the 1 :200 log plots. All logging tools should be accompanied by appropriate wireline cutting equipment, fishing tools and other attachments that may be required to aid logging e.g. a hole finder. Verify they are onboard. Pipe conveyed logging equipment should be available onshore for . mobilisation at short notice even when not specified in the logging programme. Check its availability.

5-2


Log Witnessing The Witness should supply the logging engineer with the following information for the log header; • Company Name • Well Name • Location co-ordinates Drillers Depth • Reference Point or Datum. Nomally the rig rotary table. It should be recorded as MDBRT (measured depth below rotary table) • Water Depth • Casing size and depth • Hole Size • Name of Witness • Time circulation stopped • A mud sample collected after circulation was stopped, with a mud report on mud properties. Also provide a fresh mud filtrate sample and a filter cake sample. Prior to commencing an operation at the wellsite, a pre-job meeting should be organised to ioclude the wireline crew, the logging witness, the drilling supervisor, the wellsite geologist, the toolpusher and other key personnel. The purpose is to ensure that all personnel involved are familiar with planned work programme and the procedures to be followed in executing it. • Roles and responsibilities of personnel involved. • Safety and operational procedures to be followed. • Safety and operational risks and hazards. • Work programme objectives and issues critical to the success of the operation. • Well control procedures.


5-3

Log Witnessing • Well status highlighting issues which could impact the planned operation. • Operator management approvals for approved work programme. • Well evaluation tools or equipment should not be modified without the approval of the onshore supervisor of the company who supplied the tools. • Loads should not be lifted over the wireline or coiled tubing whilst operations are in progress. If an important lift is required during the course of operations the wire or coil should be clamped and laid down prior to making the lift • Loads in excess of the working strength values of the slickline, wireline or coiled tubing set by service providers will not be exceeded without the approval of the Drilling Supervisor.

Depth Control Ensure the logger checks the casing depth while going in the hole. Any variance between loggers and drilling casing depths should be resolved. Depths measured with casing are usually much closer to wireline depths; driller and logger should agree within 2ft at 5000ft, and within 5ft at 10000ft. First Log On the first log in a well the tool should be zeroed at the level of the Derrick Floor. Following the standard checks on the cable mark, the tool should be stopped on entering open hole and the casing shoe logged. Any discrepancy of more than 2 ft at 5000ft , and 5ft at 10,000ft between casing depth and log depth should be investigated. For this purpose it is useful to retain each tally list on the wellsite. If the reasons for the discrepancy are not clear, the log may be run and the surface zero depth checked at the end. If any depth adjustments are deemed to be necessary after logging these should be recorded in the remarks section on the log and applied before any playback tapes or data transmissions are made. Subsequent Logs Subsequent logs over the Same interval should be tied into the first survey, and any depth adjustments again applied before playback, transmission or field tape production. Ensure the logger ties in with the previous run.

5-4


Log Witnessing All subsequent surveys should be run on absolute depth. In addition to the checks above, deeper surveys should include a section of overlap using through-casing gamma ray. If this overlap agrees within the tolerances given above with the previous log, after stretch correction, the depths, should be matched and logging continued, if the discrepancy is outside the above tolerances the reasons for this should be investigated. If it is established conclusively that the new depths are more accurate this should be noted in "Remarks" and the survey can be run with a through-casing gamma ray recorded over the previously logged intervals for correlation. If the shallower logged interval is still in open hole, the complete interval should be re-logged in the event of a depth adjustment. As an additional independent check on depth control a short section of log over the casing shoe should be recorded on the first descent of every set of logs, after stretch corrections have made but before tying in and proceeding to TD. As noted above, the casing shoe depth should agree with the drillers depth within 2ft at 5000ft and 5ft at 10,000ft. The depth shift must be noted while logging up to account for the cable stretch due to the change in cable tension. The amount of stretch should be comparable to stretch charts and the stretch formula. Pay particular attention to the depth units of the correction chart versus those being used for the logging. Depth for cased hole logs Surveys which include a gamma-ray should be tied in to the appropriate openhole density-neutron log. Surveys without a gamma- ray should be tied in to the CBL using the CCL. If a pup joint is present it should be logged and presented if not, enough casing joints must be logged above and below the zone of interest to avoid ambiguity. Investigating Depth Discrepancies: In the event that drillers and loggers casing shoe depths are substantially outside the quoted tolerances, the following checks should be undertaken: • Were the logging contractors depth control procedures applied correctly? • Was an excessive shift applied to tie in to the previous run? • Check the addition on the casing tally. In the event that neither of the above show any discrepancy, the problem should be discussed with the duty petrophysicist and consideration may be given to logging a CCL inside the casing to surface and checking this in detail against the


5-5

Log Witnessing tally sheet. With this in mind a CCL should be included in the first or second tool string in each logging suite. Change of Derrick Floor Elevation or Rig In the event of a change of rig or adjustment in derrick floor elevation in the course of drilling a well, all log depths should be still referenced to the original Derrick Floor elevation. In the case of development wells drilled from a jack-up, a permanent datum should be established on the wellhead or casing hanger. The original Kelly Bushing height above this datum should be reported on the log headings. The current Kelly Bushing (or deck) height should be noted in "Remarks" and the difference added or subtracted when zeroing the tool at surface before logging. In the case of wells drilled from floaters, mean-sea-level will remain the permanent datum.

Formation Temperature Where temperatures in the hole are expected to be close to the logging tool limits it is suggested that the time spent on bottom is minimized and that logging commences as soon as the tool gets to bottom. All depth corrections can be made later when the tools are in a less hostile environment. This will also have a bearing on where the repeat sections are performed

Other All formation tester, sidewall sample and CBL runs should be tied in to the appropriate density log Observe and record any adverse hole problems while RIH. Report these directly to the drilling supervisor. Where possible, record data whilst RIH as an insurance in case of tool failure. Do not slow the RIH operation to acquire quality logs. Log down from the casing shoe to a point several hundred feet above TD at maximum speed without the log overspeed aborting. Then log down a short section near TD at normal logging speed (900 or 1800ft/hr) for depth correlation purposes. In 99% of cases the insurance log will never be needed. A repeat section of at least 50 m should be recorded over a zone where log responses show large variations, e.g. a sand/shale sequence. Additional repeat sections should be run over any intervals that show anomalous log responses. A print of the repeat section should be given to the witness prior to repeat logging of the interval.

5-6


Log Witnessing All logs (with the exception of the NMR and resistivity logs) should be run at least 50 m up into the casing. If no casing has been run since the previous logging run then all logs should overlap the previous run by at least 50 m. On the top hole log the GR shall be continued inside the casing to the mudline. The Sonic log should be run inside the casing recording ∆tc to top of cement. Following all open hole logging runs a depth zero check at surface should be mandatory with any depth error reported in the log header remarks. If this error exceeds +/-5ft per 10,000ft well depth the reason must be given. Where the zone of interest has been partially logged subsequent runs should cover the entire zone of interest. If a continuous temperature log is not being run in combination with the cable tension head then 3 thermometers should be run on all logging sondes, and the maximum temperature is to be recorded on the log header. If difficulty is experienced running logging tools to the bottom of the hole, the engineer will in any case log out from the deepest point reached bearing in mind that the tool may stick at a shallower depth on subsequent runs. During Pipe Conveyed Logging the drill pipe must not be rotated or significant weight used to push the tools through any tight spots. The maximum compression possible on a tool string should be defined in the programme and agreed with the Driller. TD should not be tagged with the tools While TLC logging the side entry sub must not enter open hole In the event that a wireline tool string is stuck in open hole the maximum pull of 75% of the minimum weak point rating without exceeding 5O% of the cable breaking strength may be applied. Before the decision is made to pull any weak point the drilling supervisor must be informed. Where logging tools with a nuclear source are stuck in hole then every effort must be made to retrieve the sources fishing. On no account should tools with nuclear sources be milled or washed over. In the event that a wireline tool string with nuclear sources is stuck in hole then reverse cut and thread should be used. When new logging cables are used, precautions must be taken during the first 5 runs in hole according to the relevant Logging Contractor Procedures. Where a new cable is used then reference to the revised running procedures and increased job times must be included in the work programme


5-7

Log Witnessing Temperatures must be checked after every run in hole and recorded in the log header. All hole and tool concerns should be logged in the remarks section of the log header. Note all points of interest in the remarks box. There are several ways of numbering logging runs. Here is one recommendation. The numbering of logging run on all new wells will be as follows, where 1 represents the first evaluation suite on the well and a, b, c etc. represents the individual runs, e.g. First Evaluation Suite

Second Evaluation Suite

First run-in-hole

1a

Second run-in-hole

1b

Third run-in-hole

1c

First run-in-hole

2a

Second run-in-hole

2b

Figure 1: Log Numbering

The wellsite witness should use the logs to carry out a "quick look" interpretation at the wellsite, and email the results to the operator. The interpretation should include formation tops, top and bottom of each reservoir interval, together with details of thickness, porosity and water saturations of all significant porous zones penetrated. All logs must be digitally recorded on magnetic tape or CD Field prints of all logs are to be produced on both 1:500 and 1 :200 vertical scales. Each 1:200 scale log with wall contact or centralised logging tools should have a cable tension curve recorded on the least crowded track. Repeat section plots to be attached to the 1:200 print. QC logs and log calibrations should be included as part of the final log print At the end of each logging run the Logging Engineer will provide the witness with: • A disk containing the main FE curves acquired (LAS Format) • A log print of the data acquired • Plot files of log prints

5-8


Log Witnessing including QC and repeat sections • Header information (Mud type, MW, Vis, BHT, Rm & Rmf if appropriate) At the wellsite four (4) sets of prints is normal for each log. One set of prints should be retained at the wellsite. Two (2) sets of prints should be packed in a separate envelope and sent to the operations geologist, and I set of prints are to accompany the raw data tape to the wireline company’s office. (Sepia logs may be requested if unable to print plot files). At the end of the job the logging engineer shall supply the witness with; • 4 field prints (as mentioned above) • Printout of logging diary (note the witness and logging engineer shall discuss and agree on what was downtime, non productive time and operational time. • Job tickets to be verified by witness and authorised by the drilling supervisor • A diary of times and activities and comments (The witness and the logging engineer should agree which events will be classed as downtime).

Time Breakdown and Downtime A record of logging time breakdown should be made. Times should be recorded to the nearest 15 minutes and rig up and running times should be recorded separately. Running time is taken from when the tool leaves the surface until it is back on the drill floor. The rig down time for all but die last tool can be included in the rig-up of the next tool. Downtime should be reconciled between witness and logging engineer before submission of his tickets to the drilling supervisor. The logging contractors Real Time Acquisition Tape and the original log will be hand carried to the contractor's office at the end of the job by the logging engineer. The tape will also contain a full set of presentation and raw log plots for the repeat section. A copy of this tape should be sent to the operator with a verification listing and a paper print of the log. The engineer will generate Digital data tapes or CD containing full waveform data of all display and raw logs, including


5-9

Log Witnessing repeat section logs, (LIS Format). A final set of plot files on CD - (6 copies) should be sent to the operator for distribution.

Post-Job Responsibilities After logging all tools that are on rental should be returned to base on the first available boat to minimise rental charges. Note: Any tools that may be required to assist operational decision may be left on the rig e.g. in the event a formation pressure measurement is required before making a coring run decision then a GR/FMT™ or RFT™ sonde may be left at the rig site. Large sums of money are spent on logging operations. Even larger sums are at stake when wrong conclusions are made based on faulty logs. Carefully checking the log quality is essential.

Wireline Operations - Cased Hole Where well pressure is expected, full Pressure Control Equipment (PCE) with grease injection head should be used on all wireline rig-ups, the number of flow tubes required will be calculated ~ 00 the maximun anticipated shut in wellhead pressure of the well to be worked on. A toolcatcher and/or a tooltrap should be included in the rig-up for all wireline operations with PCE. All wireline tool strings should include a depth correlation device. A rope socket weak point feature should be included in all wireline tool strings to facilitate the release of the cable from the tool string should the tool string become stuck down hole. . The weak point release value and the weight bar requirement should be calculated for each operation based on the well pressure, depth and expected application. Loads in excess the service providers recommended value should not be applied without the approval of the drilling supervisor. For wireline perforating operations the weak point calculations must allow for a safety factor of 3 (maximum gun string weight less than 1/3 of the available weak point rating). Contingency procedures should be in place to address any of the following incidents during wireline operations installation alarms: • Parting of the wire • A leak in the riserl lubricator or BOPs

5-10


Log Witnessing • A leak at the grease injection head • Tools becoming stuck downhole • Powerpack failure.

Wireline Logging - Reporting Daily Reporting During wireline logging operations the logging witness should prepare a morning report and distribute it via e-mail or fax or the web-based reporting system. The report should be distributed to all personnel involved. The report should include: • Brief summary of operations • Detailed description of operations with time • A look-ahead with estimated timing of outstanding operations • Summary tables of pressure points, side-wall cores.

Issue Draft Evaluation Report After the job the logging witness should issue a draft evaluation report.. The report should contain the following sections: Introduction. A summary of the daily operations based on the individual daily reports, covering: • Significant dates of logging operations • Overview of each tool faiure or NPT event • Overview of data quality • Discussion on any hole problems • Any services issues which were not classed as tool failures or NPT.


5-11

Log Witnessing Time breakdown Job summary Non Productive Time analysis A detailed breakdown and analysis of the non productive time giving root causes and actions taken Log quality control A section on log quality control should reference In each logging run made and notes on the following aspects for each run should include: • Log presentation • Calibration • Logging speed • Data quality/spurious readings/repcatability.

Overview of contractor performance A listing of the services with a discussion of the following points: • Pre job description • Surface cquipment • Downholc equipment • Operations • Reporting • Personnel • Other - onshore support, logistics etc. All positive and negative points should be included and particular reference to good performance of the individuals. Recommendations and lessons learned Any operational or service issues will be subject to a post job critical review with a summary of lessons learned included in this section.

5-12


Log Witnessing Appendices • Operational Progress • Logging Programmee • Temperature (see below) • Pressure Plots • Quick Look Evaluation

Formation Temperature The static bottom hole temperature can be estimated with a "Horner plot". After two or more electric logs have been run, their respective bottomhole temperature data can be used to construct the plot by following the next steps: (I) Time the last circulation on bottom before logging was started (A). (2) Time the last circulation on bottom before logging was stopped (B). (3) Total circulation time (in hours) on bottom before logging: T = (B - A). (4) Time the logging tool arrived on bottom (C). (5) For each log calculate the time (in hours) between end of circulation (B) and tool on bottom: At = (C - B). (6) For each log calculate the following relationship: X = At/(T + At). (7) For each log record the maximum hottomhole tempe!1lture. . For each log the value for the (log X) can now be plotted against its bottomhole temperature on a semi-logarithmic graph with (log X) plotted on the x-axis and the temperature on the y-axis. Fit a straight line through the points and extend the line to where it intersects the y axis for X = 1.00. The temperature at the intersection point will be an estimate for the static bottomhole temperature.


5-13

Log Witnessing

5-14


Logged Service

JOB TIME BREAKDOWN

8:45

Start Rig Up

1.18

9:45

Start RIH

Wireline Rig Up

1,000

Chlorides (mg/l)

Mud Weight (SG)

No. Pressure tests attempted? No. Successful pressure tests ? No. Tight tests? No. Seal failures ? No. samples recovered/attempted?

MDT

Sampling Operations Run 1

Run 2

2.2

HGS (barite) %

1:39

10:45

Run 3

Total

14:15

Time at TD last Out at surface

nil

K+ (ppm)

09/15/98

Date :

16:00

Finish Rig Down

Suite 1

18 5/8"

117

17.755"

ID (inches)

Not Run

MCST

1720.0

25.0

Logged Logged from to (mLOGbrt) (mLOGbrt)

nil

76

Max Temp (°C)

0:20

Lost time (hrs)

20bbls total losses (13/09/98)

Hydrocarbon in mud? Remarks (losses, any other additives, eg (specify oil, diesel, etc) % soltex)

1192

Depth Max Last Casing Last Casing Last Casing deviation Size depth (m (m ddbrt) ddbrt)

Logging Suite No :

Wireline Rig Down

nil

LCM Content (lb/bbl)

0.75

Circulation Max Well duration @ TD Deviation (hours) (deg)

Remarks ( operations, downtime, fishing, coring etc.) 1. 20 mins lost time due to generator tripping out whilst logging up. Rmc = 1.325 ohm.m @ 32.1 deg C; Rm = 1.071 ohm.m @ 33.2 deg C; Rmf = 0.474 ohm.m @ 33.2 deg C. 2. 3. 4. 5. 6. 7. 8. 9. 10. Water Table Depth : 160mBRT BHT Estimation from Horner Plot Estimated BHT (deg C) ; -91.1

1A DLL/DSI/GR/GPIT/EMS/SP

Run No.

WBM Gel/Pac System

23:40

Time Circulation Stopped

1743

TD Depth (m ddbrt)

15/09/98 (12:00) 09/28/98 Basic Mud Information Mud Type (OBM / WBM)

Well Name:

LQC

Basic Drilling Information Date and time bit Date section started reached bottom drilling

Wireline Logging Summary

12 ¼” Hole Section

Calleva 28/05/02

Total Depth 9560 ft Casing 3320 ft

Start Time

Stop Time

Elapsed Time

22:00 22:05 23:45

22:05 23:45 0:40

0:05 1:40 0:55

0:40 1:20 1:30 4:10 4:30 6:40 7:40 8:00 8:15 9:15 9:30 10:30 10:45 12:18 12:20 12:38 12:40 12:47 12:49 12:57 13:01 13:10 14:25 15:15 16:32 16:37 16:42 16:45 17:10 17:15 17:20 19:00 20:30 21:10 21:30 23:24 23:34

1:20 1:30 4:10 4:30 6:40 7:40 8:00 8:15 9:15 9:30 10:30 10:45 12:18 12:20 12:38 12:40 12:47 12:49 12:57 13:01 13:10 14:25 15:15 16:32 16:37 16:42 16:45 17:10 17:15 17:20 19:00 20:30 21:10 21:30 23:24 23:34 0:00

0:40 0:10 2:40 0:20 2:10 1:00 0:20 0:15 1:00 0:15 1:00 0:15 1:33 0:02 0:18 0:02 0:07 0:02 0:08 0:04 0:09 1:15 0:50 1:17 0:05 0:05 0:03 0:25 0:05 0:05 1:40 1:30 0:40 0:20 1:54 0:10 2:18

0:00 1:50 13:24 15:30 16:00 16:45 17:00 19:25 21:00 21:15 23:10 23:35

1:50 13:24 15:30 16:00 16:45 17:00 19:25 21:00 21:15 23:10 23:35 0:43

1:50 11:34 2:06 0:30 0:45 0:15 2:25 1:35 0:15 1:55 0:25 1:08

0:43 1:17 1:27

1:17 1:27 2:59

0:34 0:10 1:32

2:59 3:15 3:36 3:45 4:45 6:40 7:10 8:40 9:00 10:00 11:00 11:25 11:55 12:03 12:45 12:52 13:00 16:15

3:15 3:36 3:45 4:45 6:40 7:10 8:40 9:00 10:00 11:00 11:25 11:55 12:03 12:45 12:52 13:00 16:15

0:16 0:21 0:09 1:00 1:55 0:30 1:30 0:20 1:00 1:00 0:25 0:30 0:08 0:42 0:07 0:08 3:15

Wireline Activity 29th December 2001 toolbox talk begin rig up of Run #1: SP-DSI-HRLA-PEX toolbox talk for next crew 30th December 2001 check toolstring load RA sources RIH on bottom, repeat pass main pass at casing shoe finish GR log unload RA sources finish after cals, Max Recorded Temps: 182, 181 degF finish rigging down Run #1, head changed, wait on crane lifts begin rigging up Run #2 operational check tool string RIH with FMI-HNGS-CMR at 8940 ft, open caliper Run #2 pass 1: FMI-HNGS log up repeat section, 900 fph, all buttons active at 8700 ft, close calipers RIH to 9250 ft, open calipers log up main pass, 900 fph, pad press. 17%, every 2nd button on one pad & flap inactive abort log at 9160 ft, close caliper & RIH to 9250 ft, to try again log up main pass 2nd attempt, 900 fph, pad press. 50%, same pad/flap problem at 8200 ft, stop log, retract arms, RIH log up main pass Run #2 pass 2: CMR after tuning tool, 850 fph stop log at 8200 ft, RIH to 8732 ft, tune CMR RIH to 8850 ft start repeat section at 8778 ft end repeat section & drop down to 8732 ft to tune tool tune CMR POOH perform after cals, rig down FMI-HNGS-CMR, MRT 183, 182 degF rig down FMI-CMR complete rig up Run #3: MDT pressure tests RIH Turn on motion compensator stick test 1st correlation pass 31st December 2001, New Year's Eve stabilize temperature of MDT tool in hole at 8565 ft MDT pressure profile. 49 pressures attempted, 26 obtained, 16 dry tests, 7 lost seals POOH with MDT, Pressure survey completed wash down & flush out single probe rigged up additional MDT sampling modules to run #3 MDT tool surface check Run #4: MDT samples RIH to 8450 ft perform stick tests & allow, MDT to warm up correlation log to position for sample at 8468 ft Pumped out 39.7 litres and filled 3.74 litre sample chamber at 8468 ft with water correlation log to position for sample at 8938 ft Pumped out from 8938 ft, MDT tool plugged up after pumping 30 litres 1st January 2002, New Year's Day Pumped out from 8936 ft, MDT tool plugged up after pumping 27 mins of pumping correlation log to position for sample at 8664 ft pumped out from 8664 ft. After pumping for 1.5 hrs O/W ratio was 50/50. Aborted sampling since a 95% pure sample could not be obtained. Attempted to sample at 8561 ft, Aborted sampling after dry pretest Attempted to sample at 8563 ft, Aborted sampling after MDT tool plugged Attempted to sample at 8598 ft, Aborted sampling after dry pretest Attempted to sample at 8600 ft, Aborted sampling after MDT tool plugged Pull MDT tool out of the hole for inspection & servicing Turn off motion compensator, toolbox talk drain SC#1, sample from 8468 ft, volume 3750 psi probe plugged, took 3000 psi to clear, service tool begin making up MDT toolstring for run #5 surface check Run #5: MDT samples operational check Set compensator, RIH correlation run for sample at 8563 ft, add 3.5 ft Attempt sample at 8563 ft, aborted as sample not cleaning up above 50% oil Attempt sample at 8620 ft, telemetry failure, tool retracted automatically. Drop down to 8635 ft, no communication with tool. POOH, found short in cable head, rehead, lay out MDT (program cancelled) Rig up Run #6: VSI

Page 1 of 1

2:25

2:38

2:51

3:03

3:16

3:29

3:44

3:57

4:12

4:29

4:38

4:52

5:05

5:16

5:30

5:46

5:58 6:11 6:23 6:32

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19 20 21 22

11:00 11:00 07:20 11:50

09:30

13:20

12:10

09:20

11:10

11:10

07:40

14:20

12:20

10:20

13:00

11:10

10:00

08:30

11:00

10:50

10:02

Time

6:09 6:22 6:30 6:43

5:55

5:43

5:28

5:14

5:03

4:49

4:36

4:26

4:09

3:54

3:42

3:27

3:13

2:59

2:49

2:35

2:22

2:09

2:02

hh:mm

Finish

62 63 64 65

61

60

59

58

57

56

55

54

53

52

51

50

49

48

47

46

45

44

43

#

File

Well: Calleva 28/05/02

8720.0 8730.0 8740.0 8742.0

8682.0

8684.0

8672.0

8674.0

8664.0

8656.0

8654.0

8635.0

8627.0

8620.0

8611.0

8606.0

8592.0

8591.0

8581.0

8571.0

8563.0

8551.0

8565.0

(ft)

MDBRT

8718.7 8728.7 8738.7 8740.7

8680.7

8682.7

8670.8

8672.8

8662.8

8654.8

8652.8

8633.8

8625.8

8618.8

8609.8

8604.8

8590.8

8589.8

8579.9

8569.9

8561.9

8549.9

8563.9

(ft)

TVDBRT

Depth (Ft)

5101.4 5107.1 5112.9 5114.1

5079.6

5081.2

5074.0

5075.1

5069.2

5064.8

5063.6

5052.7

5048.0

5044.0

5038.6

5036.0

5027.7

5027.0

5021.2

5015.2

5010.9

5003.7

5011.6

(PSIA)

SG

5101.6 5107.2 5112.9 5113.7

5079.5

5080.8

5073.5

5075.1

5069.4

5064.6

5063.5

5052.7

5048.0

5043.9

5038.6

5035.7

5027.6

5026.9

5020.8

5015.1

5010.5

5003.4

5011.4

(PSIA)

CQG

11.23 11.23 11.23 11.23

11.23

11.23

11.23

11.23

11.23

11.23

11.23

11.23

11.23

11.23

11.23

11.23

11.23

11.23

11.23

11.23

11.23

11.23

11.23

(lb/g)

EMW

Hydrostatic Before

Large Diameter Probe Used

4595.7 4599.4 4603.0 4603.8

4583.0

4584.4

4578.8

4582.2

4575.9

4573.1

4566.4

4563.0

4560.6

4557.5

4555.6

4550.6

4550.0

4546.5

4543.2

4540.5

4541.1

(PSIA)

SG

4596.0 4599.5 4602.6 4603.7

4583.0

4584.5

4578.9

4582.3

4576.0

4573.1

4566.5

4563.0

4560.7

4557.4

4555.5

4550.4

4550.0

4546.2

4542.8

4540.1

4540.7

P(PSIA)

CQG

Grad

10.11 10.11 10.10 10.10

10.13

10.13

10.13

10.13

10.13

10.14

10.15

10.15

10.15

10.15

10.15

10.16

10.16

10.16

10.17

10.17

10.17

6.86 6.85 6.80 6.85

6.95

7.07

6.86

7.32

6.85

6.84

7.07

6.90

6.97

6.95

6.91

6.86

6.83

6.52

6.49

(lb/g) (lb/g)

EMW

Formation Pressure

5101.5 5107.2 5113.1 5114.4

5079.6

5080.8

5074.0

5075.1

5069.4

5064.7

5063.6

5052.9

5048.0

5044.0

5038.6

5035.6

5027.7

5026.9

5021.1

5015.5

5010.7

5003.7

5011.6

(PSIA)

SG

5100.7 5106.4 5112.7 5113.3

5078.8

5080.0

5073.1

5074.3

5068.6

5064.0

5063.0

5051.8

5047.2

5043.1

5037.9

5035.4

5026.9

5026.7

5020.5

5014.8

5010.2

5003.4

5011.2

(PSIA)

CQG

Hydrostatic After

Date : 20th May 2002

171.2 171.4 171.6 171.7

171.0

170.8

170.6

170.5

170.3

170.2

169.9

169.7

169.4

170.0

168.5

168.3

167.8

167.5

166.9

166.3

165.6

164.6

DegF

Temp

1007.5

1744.6 481.5

996.9

105.9

561.5

2383.1

940.6

78.3

951.1

1179.1

206.7

133.2

1989.2

664.0

1380.6

773.5

11.8

MD/CP

Mobility

7:22 7:47 8:03 8:13 8:25 8:42 8:52 9:00 9:08 9:18 9:27 9:42

12:50 11:50 06:40 06:40 15:40 07:00 06:50 05:40 06:40 06:40 11:40 08:20

7:34 7:58 8:09 8:19 8:40 8:49 8:58 9:05 9:14 9:24 9:38 9:50

71 72 73 74 75 76 77 78 79 80 81 82

8756.0 8768.0 8777.0 8778.0 8797.0 8854.0 8853.0 8855.0 8871.0 8873.0 8877.0 8898.0

8754.7 8766.6 8775.7 8776.6 8795.7 8852.6 8851.6 8853.5 8869.6 8871.6 8875.5 8896.5

5118.5 5125.9 5130.9 5131.2 5142.2 5175.0 5174.2 5175.5 5184.9 5185.8 5188.6 5201.0

5118.2 5125.6 5130.8 5131.3 5142.1 5175.3 5174.5 5175.5 5185.0 5186.2 5188.5 5200.7

10:07 10:16 10:26 10:35 10:51 11:05 11:17 11:25

07:20

07:20 07:40 06:40 14:10 12:30 10:30

10:14 10:23 10:32 10:49 11:03 11:15 11:17 11:32

85 86 87 88 89 90 91 92

8912.0 8922.0 8924.0 8925.0 8930.0 8938.0 8967.0 8986.0

8910.5 8920.5 8922.6 8923.5 8928.5 8936.5 8965.5 8984.5

5210.7 5216.4 5217.9 5217.5 5220.8 5225.5 5242.2 5253.4

5210.6 5216.3 5217.7 5217.4 5220.8 5225.5 5242.2 5253.5

11:47

11:40

11:58

95

8986.0

44 45 46 47 48 49

12:16 12:35 12:47 13:01 13:09 13:17

07:00

14:10 09:20 10:00 06:30

12:30 12:44 12:57 13:07 13:09 13:24

97 98 99 100 101 102

8472.0 8468.0 8468.0 8462.0 8463.0 8464.0

Pulled MDT Out of the Hole to ~ 8500 ft.

43

8471.0 8467.0 8467.0 8461.0 8462.0 8463.0

8985.5

4960.2 4957.2 4957.1 4953.4 4953.9 4954.2

5256.2

4958.4 4956.0 4956.1 4952.7 4953.2 4953.6

5256.1

Correlation Pass Logged. Subtracted 3 feet to put MDT on Depth.

35 36 37 38 39 40 41 42

Correlation Pass Logged. Subtracted 3 feet to put MDT on Depth.

23 24 25 26 27 28 29 30 31 32 33 34

11.23 11.23 11.23 11.23 11.23 11.23

11.23

11.22 11.22 11.22 11.22 11.22 11.22 11.22 11.22

11.22 11.22 11.22 11.22 11.22 11.22 11.22 11.22 11.22 11.22 11.22 11.22 4646.8

4647.4

4348.2 4346.3

4347.5

4686.5

4350.0

4687.0

4663.6 4665.4 4668.0

4621.8

4622.3

4664.0 4665.6 4668.3

4606.2 4609.7

4606.8 4610.2

9.84

9.84

10.01

10.03 10.02 10.02

10.04

10.08

10.09 10.09

6.65

6.57 6.58 6.57

6.55

6.72

6.60 6.54

4959.7 4957.3 4956.9 4953.1 4953.7 4954.4

5256.4

5210.6 5217.0 5217.6 5217.6 5221.2 5225.6 5242.4 5253.4

5118.9 5125.7 5129.9 5131.4 5142.5 5175.0 5173.9 5175.5 5185.0 5186.4 5188.9 5201.0

4958.4 4956.0 49561.0 4952.7 4953.0 4953.8

5256.2

5210.5 5216.2 5217.6 5217.3 5220.7 5225.3 5242.3 5253.4

5118.5 5125.3 5130.8 5131.1 5142.2 5175.2 5174.7 5175.8 5185.3 5186.2 5188.3 5200.6

178.3 176.8 175.5 174.0 173.8 173.6

180.5

180.0

179.0 179.0 179.3 179.2 179.4 179.6

178.3

175.5 176.0 177.4

172.8 173.0 173.2 173.5 173.9

138.6

91.8

140.7

1326.7 378.0 682.9

161.0

41.6

380.8 263.1

Good Test Test with Lost Seal ??? Good Test Dry Test Dry Test Dry Test

Good Test

Dry Test Dry Test Dry Test Good Test Good Test Good Test Dry Test Dry Test

Good Test Good Test Dry Test Dry Test Good Test Dry Test Dry Test Dry Test Dry Test Dry Test Good Test Dry Test

Good Test Good Test Lost Seal after Good Pressure Good Test

Good Test

Good Test with Lost Seal ???

Good Test

Good Test then Lost Seal

Good Test

Good Test

Lost Seal

Good Test

Good Test

Good Test

Good Test

Good Test

Good Test


Good Test

Good Test

Good Test

Check Seal in Shale - OK


Comments

All pressures in PSIA

Mobility based on CQG readings.

Correlation Pass Logged. MDT Off Depth by 6 feet. Stations 23 & 24 have to have 6 feet subtracted from the TVD for Gradient Studies.

2:12

04:40

2:05

2

11:00

1:51

1

mm:ss

hh:mm

Time

Elasped

Time

Start

#

No

Stag Geological Services Ltd.

Stag Oil Company Ltd. JOB LOG FIELD: Berkshire

WELL: Calleva-10A

RIG: Land -1

WITNESS: Dave Kitson

DESCRIPTION: MDT / CMR

DATE

TIME

RUN NO.1 LATCH 1.

28/09/00

00:15 01:00 03:00 03:45 06:35 06:50 07:10 08:10 08:35 08:16 08:48

Rig up sheaves Rig up tools (MDT/CMR), total length 178.7 ft Power up tools at surface and test, OK. Start RIH (Drift Pipe) At Shoe, 4,371 ft, circ pipe volume Resume RIH to 4749 ft Make up SES and RIH w/ PWCH Latch and Test – OK R/U Snatch Pulley Clamp cable and Pull Test to 3000 lbs Start RIH to Station 1

09:05 09:10 09:28 09:30 09:34 09:38

STATION 1 at 4,780 ft, allow Hydrostatic to stabilise Inflate Packer with 24.57 ltrs / 800 psi / Hole Dia 9.1 ins Set Observation Probe Probe Pre-test 1b, draw 10 cc Probe Pre-test 1c, draw 10 cc Packer Pre-test 1a, Pump out of packer 585 cc, pulse seen on Observation probe Packer Pre-test 1d, Pump out of packer 585 cc, pulse seen on Observation probe Retract Observation Probe Pre-test 1e, Pump out of packer 500 cc Deflate Packer, Establish Hydrostatic End Station 1. Move down to next station

10:06 10:49 10:50 11:04 11:15 12:10 12:12 12:25 12:26 12:29 12:30 12:33 12:36 12:42 13:00 13:36 13:40

13:51 14:10 14:30 14:38 14:45 15:06

STATION 2 at 5,500 ft, allow Hydrostatic to stabilise Inflate Packer with 23.9 ltrs / 900 psi / Hole Dia 9.1 ins Set Observation Probe Set Resistivity Probe Probe Pre-test 2c, draw 10 cc Probe Pre-test 2b, draw 10 cc Probe Pre-test 2d, draw 9.5 cc Probe Pre-test 2e, draw 9.66 cc Packer Pre-test 2a, Pump out of packer 585 cc, large pulse seen on Observation probe Packer Pre-test 2f, Pump out of packer 585 cc, large pulse seen on Observation probe Reflate packer to 1000 psi Start pump-out for Interference Test at 350 rpm speed mode. See drop in pressure at Observation probe immediately. See drop in pressure at Resistivity probe after 10 mins. Increase pump speed to 380 rpm First water on OFA after 8.1 ltrs pumped Increase pump speed to 400 rpm Increase pump speed to 420 rpm Increase pump speed to 450 rpm Stop pump-out, Start Build up. Pumped 24.5 ltrs (25.7 ltrs cum) in 86 mins.

MDT/CMR JOB-LOG Calleva-10A

1

16:19 16:57 17:02 17:04 17:51 18:14 18:46 19:00

19:04 19:15 19:35

19:37 19:38 19:40 19:43

19:53 19:55 20:01 20:10 20:25 20:27 20:28

20:42 20:52 20:55 21:57 22:02 22:13 22:17 22:28 22:29 22:30 22:31 22:32 22:36 22:59 22:02 22:03 23:30 23:30 23:37 23:39 23:44 23:47

Start pump-out for clean-up / PVT samples at 600 rpm Packer pressure at 1403 psia after 18.7 ltrs (44.4 ltrs cum), decrease pump rate to 570 rpm. Packer pressure at 1401 psia after 20.5 ltrs (46.2 ltrs cum), decrease pump rate to 565 rpm. Packer pressure at 1400 psia after 21.6 ltrs (47.3 ltrs cum), decrease pump rate to 560 rpm. First oil (40%) after 39.1 ltrs (65.8 ltrs cum), packer pressure = 1433.32 psia Packer pressure = 1428.2 psia, after 48.5 ltrs (74.2 ltrs cum): 70% oil Packer pressure = 1424.6 psia, after 59.7 ltrs (85.4 ltrs cum): 80% oil (70% green, 10% white on OFA) and 20% water Packer pressure = 1422.7 psia, after 64.3 ltrs (90.0 ltrs cum): 80% oil (70% green, 10% white on OFA) and 20% water. Open PVT bottle # 326 for low shock PVT sample #1 Close bottle # 326 (1st PVT sample), min pressure 1422.7 psia, final pressure = 1552.29 psia (+4000 psi sealing pressure). Continue pump out Packer pressure = 1433.3 psia, after 69.6 ltrs (95.3 ltrs cum): 80% oil (70% green, 10% white on OFA) and 20% water Packer pressure = 1427.14 psia, after 77.2 ltrs (102.9 ltrs cum): 80% oil (70% green, 10% white on OFA) and 20% water. Open PVT bottle # 327 for low shock PVT sample Close bottle # 327 (2nd PVT sample), min pressure 1359.22 psia, final pressure = 1507.01 psia (+4000 psi sealing pressure). Open PVT bottle # 328 for low shock PVT sample Close bottle # 328 (3rd PVT sample), min pressure 1368.66 psia, final pressure = 1519.07 psia (+4000 psi sealing pressure). Continue pumping with inc pump rate of 1200 rpm Packer pressure = 1220 psia, after 84.3 ltrs (110 ltrs cum): 80% oil (70% green, 10% white on OFA) and 20% water. Inc to 2000 rpm w/ a minimum pressure of 1060 psia at packer and 70%oil / 30% water, no gas. Stop pump out after 93 ltrs (118.7 ltrs cum): 70%oil / 30% water, no gas. Pretest 2g at Observation probe Pretest 2h at Resistivity probe, 2g still building Pretest 2h stable at 1601.34 psia, 2g still building Retract Resistivity probe, stable at 1601.35 psia Retract Observation probe, not quite stable at 1604.48 psia, final packer pressure 1596.72 psia Deflate packer, establish final hydrostatic pressures, unable to get good mobility results from probe tests due to length of test and interference from pump out. Set Observation Probe for Pretest 2i for mobility data Unset probe, obtain hydrostatic and a good mobility End of Station 2. Move down to next station STATION 3 at 6,550 ft., allow hydrostatic to stabilise Pretest 3a on observation probe for mobility data: 14.4 md/cp End pretest 3a, unset probe Start Packer inflation at 6,550 ft MDRT Packer inflated with 19.89 ltrs / 1000 psi / Hole Dia 8.7 ins Set Observation Probe Set Resistivity Probe Probe Pre-test 3d, draw 5.4 cc Probe Pre-test 3c, draw 5.6 cc Packer Pre-test 3b, Pump out of packer 2340 cc, interference seen on Observation Probe Repeat Packer pre-test (3e), interference seen on Observation Probe Observation Probe Pre-test 3f, draw 5.4 cc Resistivity Probe Pre-test 3g, draw 5.4 cc and allow all three pre-tests to stabilise. Start pump-out for Interference Test at 700 rpm speed mode. See drop in pressure at Observation Probe immediately. Packer pressure 1516.6 psia Increase pump speed to 1200 rpm Increase pump speed to 2000 rpm Pumped 11.11 ltrs (15.2 ltrs cum). Switch pump from constant speed mode to constant power mode at 70% duty cycle Pumped 7.0 ltrs (22.2 ltrs cum). Increase duty cycle to 75% Pumped 13.0 ltrs (28.2 ltrs cum). Increase duty cycle to 80% Observation Probe at 1609.41 psia. Resistivity Probe 1614.97 psia

MDT/CMR JOB-LOG Calleva-10A

2

8b Probe 8c Probe

6e Probe 6f Probe

1 1

1 1

6d Packer

1

7a Probe

6c Probe

1

8a Packer

6b Probe

1

1

6a Packer

1

1

5b Probe 5c Probe

4b Probe

1

1 1

4a Packer

1

4c Probe

3b Probe 3c Packer

1 1

5a Packer

3a Packer

1

1

2d Probe

1

1

2b Probe

1

2c Packer

2a Packer

1

1

1e Packer

1

1

1c Probe

1d Probe

1

1a Probe

1b Packer

1

Test No.

1

No.

Latch

Well: 11111.0

NU NU

NU

NU

KB KB

KB

KB

KB

KB

SHU SHU

SHU

SHU

SHU

SHU

NU NU

NU

NU

NU

NU

NU

NU

NU

NU

NU

NU

RUN No. 2

Unit

3032.4 3032.4

3039.0

3028.0

3358.4 3358.4

3365.0

3358.4

3358.4

3365.0

3059.4 3059.4

3066.0

3057.4

3057.4

3064.0

3024.4 3031.0

3031.0

3026.4

3033.0

3026.4

3033.0

3029.5

3022.9

3022.9

3029.5

3022.9

MDRT (ft)

Depth

2954.3 2954.3

2960.9

2949.9

3280.3 3280.3

3286.9

3280.3

3280.3

3286.9

2981.3 2981.3

2987.9

2979.3

2979.3

2985.9

2946.3 2952.9

2952.9

2948.3

2954.9

2948.3

2954.9

2951.4

2944.8

2944.8

2951.4

2944.8

MDT No. 1

TVDSS (ft)

Depth

9.7

Lith

ft

6.6

Packer-Probe Dist

Mud Weight in Hole

5.8 5.8

5.8

5.7

9.0 9.0

9.0

9.0

9.0

9.0

6.0 6.0

6.1

6.0

6.0

6.1

5.7 5.7

5.7

5.7

5.8

5.7

5.8

5.7

5.7

5.7

5.7

5.7

Section (ft)

Vertical

ppg

ft

78.0

Finish Date : RKB to MSL

LOCATION Start Date :

1576.6

1584.4

1571.8

1734.1

1734.5

1738.6

1593.6

1602.7

1588.0

1596.4

1571.4

1580.1

1573.2

1582.3

1573.9

1581.7

1573.9

(Suite No. 2)

Hydrostatic (psia)

Initial

15:33

15:32

14:20

05:56

05:01

05:00

02:15

02:14

23:48

23:46

22:15

22:14

20:04

20:03

18:36

17:48

17:51

Set

Time

3314.0

Kharaib

3007.0 3035.0

Shuaiba

Nahr Umr

6.0 5.9

2340.0

0.5

5.9 5.9

2340.0

6.0

6.0

2340.0

0.7 0.7

1170.0

5.0

0.7

1170.0

0.5 1170.0

1170.0

0.6

2300.0

0.7

1170.0

1170.0

20.0

1.0

1170.0

0.6

(cc)

DD Vol

1686.0

1557.0

1524.0

1477.0 1471.0

1472.0

605.0

33.0 40.0

1255.0

0.0

0.0

1282.0

738.5 736.0

1121.0

0.0

517.0

1112.0

660.2 1484.5

1485.0

773.0

1497.0

706.0

1497.0

1372.5

916.0

1378.9

725.0

Pressure (psia)

Min DD

0.325

0.325

0.325

Formation Depth (ft) Pressure Fluid Density TVDSS psi psi/ft

Datum Information

1687.9 1688.1

1658.1

1691.1

1691.1

1659.6

1559.2 1558.7

1530.5

1579.3

1568.7

1531.3

1533.8 1490.3

1491.9

1560.0

1491.1

1561.3

1492.4

1563.2

1490.7

1562.8

Strain (psig)

132.7 132.9

132.4

132.2

131.9

132.1

127.4 127.5

127.3

127.1

126.7

126.8

126.6 126.6

126.6

125.7

125.7

125.7

125.6

124.3

124.7

124.2

1502.1 1502.2

1509.7

1491.2 1491.2

1493.9

128.1 128.8

127.9

-3.8 -3.7

1.1

-3.4 -3.4

0.9

-3.6

-3.8

0.8

-3.7 -3.7

0.8

-3.6

-3.9

1.0

-4.5 1.0

0.9

-25.0

0.9

-25.1

0.5

-4.9

0.7

-3.8

0.51 0.51

0.51

0.52 0.52

0.51

0.52

0.52

0.51

0.53 0.53

0.52

0.53

0.53

0.52

0.52 0.51

0.51

0.53

0.51

0.53

0.51

0.53

0.51

0.53

to MSL (psi/ft)

1519.2 1519.3

1524.7

1710.2 1710.4

1682.5

1713.2

1712.9

1683.9

1587.7 1587.2

1561.3

1608.5

1597.6

1562.9

1563.8 1523.5

1525.1

1568.8

1523.7

1570.0

1524.5

1593.2

1524.2

1593.9

Pressure (psia)

Datum

Calculated Difference Gradient

(Qtz-Strain) (deg F) (psi)

Temp

Interference From Packer Test

1699.2 1699.4

1673.7

1702.2

1702.0

1675.1

1570.2 1569.7

1546.0

1590.4

1579.5

1547.0

1544.1 1506.0

1507.5

1549.7

1506.7

1550.9

1507.6

1573.0

1506.1

1573.7

Quartz (psia)

Final Build-up Pressure

OIL

OIL

OIL

Fluid

PRE-TESTS

9.45 9.45

9.48

9.66 9.67

9.50

9.68

9.68

9.51

9.80 9.79

9.62

9.93

9.86

9.64

9.74 9.48

9.49

9.77

9.48

9.78

9.48

9.93

9.49

9.94

EMW to RT (lbs/gal)

Pressure

Formation

V Fast B/U V Fast B/U

Mod B/U

Fairly Tight

V Tight, Good B/U, S/C? V Tight, Good B/U, S/C?

Slow B/U, S/C?

V Tight, Good B/U, S/C?

V Tight, Good B/U, S/C?

Slow B/U, not fully stable

Tight S/C Tight S/C

Tight slow build up

Tight slow build up

Tight slow build up

Tight slow build up

Tight, (S/C?) B/U on 2nd Stroke

Tight, (S/C?)

Tight, (S/C?)

Good Test

Tight, (S/C?)

Good Test

Tight

Lost Seal

Tight (S/C?)

Tight, Not Stable

Tight (S/C?)

Comments/Remarks

7

8a

8 8

1

1 1

1 1

1

6

6 6

1

6

6d 1673.7

1

1

5a

1

5 5

4

1

6a

4

1

1

4a

1

1 1

3 3c

1 1

2c 1506.7

1

2

2

1

3a

2a

1

1

1e

1

1

1

1

1

1

1b

Packer (psia)

1697.0

1560.0

Probe (psia)

Initial Pressures

1

1

T

1

No.

Latch

Well: 1

1497.0

Packer (psia)

Min at

1571.7

Probe (psia)

Min at

9.7

Diff (psia)

Packer

-11.7

Diff (psia)

Probe Volume (ltrs)

Flow

Fluid

ABORTED - SAND IN VALVES

TOO TIGHT

UNABLE TO PERFORM TEST

TOO TIGHT

Time (mins)

Flow

Drawdown Pressures and Volumes

INTERFERENCE TESTS / MINI DST's

Pressure (psia)

Packer Pressure (psia)

Probe Time (mins)

Build-up

Final Build-up Data

1509.8

1673.7

1578.9

Pressure (psia)

Packer

Initial

23.0

85.0

15.0

Pumped (ltrs)

Volume

Previous

27

58

18

Pumped (mins)

Time

Previous

540.6

Pressure (psia)

Packer

165.0

Volume (ltrs)

Cum

463.0

Pressure (psia)

Packer

235.0

Volume (ltrs)

Cum

First Gas

Pump Out Details First Oil

1424.3

340.0

1485.7

Pressure (psia)

Min

223.1

349.8

253.3

Pumped (ltrs)

Volume

Cum

326.0

346.0

224.1

Pumped (mins)

Time

Cum

MDT SAMPLING CONDITIONS

100% Water

Trace Gas

40% Oil / 60% Water

100% Water

Fluid on OFA

3.0

No.

Sample No.

Chamber

Bottle/

As

1502.0

410.0

1501.2

Opened (psia)

Chamber

Sampling Details

1424.3

377.0

1388.9

Filling (psia)

While

Min

Pressures As

4053.0

4300.0

4315.0

Closed (psia)

Chamber

1

(ppm)

Dirty Water, Trace dead oil flakes with no flourescence, trace gas, no H2S

18:35

Unset

Time

Final Hydrostatic

Hydrostatic EMW to RT (psia) (lbs/gal)

Final (md/cp)

Mobility

4

1

10.75 ltrs Total, 0.27 cu ft Gas, no H2S, 8.25 ltrs dirty Water, 2.5 ltrs Oil

1571.0 1579.5 1597.7

01:24

1 1

1

1

1 1

1

1

1

1

1 1

8

6

6

3.5 ltrs

(8.25lt)

(2.5lt)

100

77

23

39000

0

Cloudy Water, Trace dead oil flakes with no flourescence, no gas, no H2S

Dull straw yellow - yellow brown flourescence, Strong H/C odour (No H2S odour and does not smell like normal Kharaib Oil)

1569.6

22:29

1572.2

1581.6

14:44 22:34

1739.6

1749.4

1734.1

1589.5

13:03

13:04

05:52

03:31

9.90

9.94

9.89

9.90

9.93

9.86

9.92

9.96

9.92

9.95

1.8 1.8

n/a

0.2 0.4

0.1

0.1

0.2 0.4

n/a

n/a

1557.0 1524.0

1524.0 1524.0

1524.0

1524.0

1524.0 1524.0

1524.0

1557.0 1557.0

1557.0

1557.0

1557.0 1557.0

1557.0

1557.0

1557.0

1524.0 1524.0

1557.0 1557.0

1557.0 1524.0 1524.0

1524.0

1557.0

1557.0 1524.0

1557.0 1524.0

1557.0 1557.0 1524.0

1524.0 1524.0

1557.0

1524.0 23:18 23:22

1557.0

1557.0 1524.0

1557.0

1557.0 1524.0

1524.0

1557.0 1557.0

1524.0 1524.0

1557.0

1524.0

1524.0 0.1

0.1

0.5

0.2

21:26 9.92 9.95

9.93

21:50

1598.9

0

0

03:22

39000

39000

1

100

1589.1

10.75 ltrs

6.0 ltrs

01:21

3

1573.2

1

5

3

1 1

1

3

1

1

1

2

2

1

1

1

1

1

1

1557.0

1557.0

1686.0 1686.0

1686.0

1686.0

1686.0 1686.0

1686.0

1686.0

1686.0

1686.0

1686.0 1686.0

1686.0

1686.0

1686.0

1686.0

1686.0 1686.0

1686.0

1686.0

1686.0

1686.0

1686.0

1686.0

1686.0

1686.0

1686.0

1686.0

Datum Pressures for Graphs Nahr Umr Shuaiba Kharaib

1524.0

(API)

Remarks Colour, Odour, Flourescence, etc

1524.0

(ohms)

H2S

Oil / Gas Gravity

0.5

(mg/ltr)

Res

Water Properties Chlorides

0.2

(%)

Water

PRE-TESTS

1

(%)

Oil

Sample Volumes

Volume (cc)

Total

SAMPLE DETAILS

1

No.

No.

No.

Bottle/

Chamber

Sample

Latch

Well:

Formation Pressure Concepts Pore Pressure Evaluation Introduction A knowledge of formation pressure is necessary to drill the well safely and economically. Mud weight has to be optimized to provide enough safety margin and yet allow drilling to proceed at a reasonable rate. Rock Fracture Pressure must not be exceeded otherwise mud will be lost, damaging the formation and risking inducing kicks and blowouts by the loss of hydrostatic pressure. Extensive use of offset and petrophysical data is made during the planning phase to identify pressure profiles and produce a workable drilling proposal. However, this data may be insufficient, particularly if there are no nearby wells. During drilling, data will be obtained and the well observed to identify the onset of pressure transition zones and to monitor the implementation of planned mud weight increases. Wellsite geologists, mud loggers and specialist Pressure Engineers can be used to evaluate formation pressures whilst drilling.

Measuring Pore Pressure Various methods exist to obtain measured values of Pore Pressure. All of them require an established borehole and will only provide pressures in permeable formations. The results are important and will confirm pressure estimates in reservoir rocks, but will not indicate pressures in clays and shales which, whilst not producing kicks or blowouts will produce severe drilling problems if significantly abnormally pressured. The methods include: • Wireline Pressure Tests (RFT, MDT etc.) The RFT tool is normally run at casing points and can provide unlimited pressure readings whilst obtaining one or two actual fluid samples. The tool will only sample porous, permeable rocks, and over a very limited area. Pressure build up in clays, very common in the North Sea, will not be sampled due to the lack of permeability. • LWD Pressure Tests LWD presure testing tools have recently been introduced by some of the major service companies. Thes include Testrak from BHI, Geotap from Halliburton and Stethoscope from Schlumberger. All of these tools are able to take pressure readings from permeable formations without the need to trip the pipe. This aids mud density optimization, ECD management and borehole stability whilst drilling.


6-1

Formation Pressure Concepts • Production Pressure Tests (Drill Stem Tests) A full scale DST performed at the end of the well will provide a great deal of useful pressure data. However only potential reservoir zones will be tested and the data will, therefore, be incomplete. Again its best use is as a means of planning future wells. • Kick The shut in pressures recorded after taking a kick allow calculation of formation pore pressure, which is necessary in order to produce the correct kill mud. This is a last resort however, and no wells are allowed to be drilled "for kicks" for safety reasons.

Indirect means for Pore Pressure Estimation Indirect methodologies require the monitoring of borehole stability, mud -gas relationships and drilling, mudlogging, wellsite geological and petrophysical data to identify pressure transition zones or closely balanced drilling situations. Long pressure transition zones in clays and shales can be monitored using the following procedures: • Evaluate Normally Pressured Sections and Establish Trends • Identify Variations from Normal Trends • Quantify Pore Pressure from those changes It should be remembered that any values of pore pressure reported from wellsite evaluation of drilling and logging data are estimates only, and not measured values. The classic techniques using drilling exponents and other data such as resistivity and sonic log information are only applicable to abnormal pressure caused by undercompaction of clays and shales.

Normal Pore Pressure A rock is said to have normal pore pressure if only hydrostatic pressure of the pore fluid column is the force acting on the fluids. In sedimentary rocks this pressure will be established if, during burial, excess fluids are allowed to escape to a low pressure environment as compaction proceeds. In this case the rock matrix material will provide a self supporting structure and the pore fluids will merely be filling the spaces and under their own pressure. The value of this expected normal pressure can be computed for any depth in the formation by knowing the average density of the pore fluids to the depth of interest and the true vertical height of the fluid column.

6-2


Formation Pressure Concepts Units of Measurement The internationally recognised unit of measurement for pressure is the Pascal (Pa). This is equal to a force of one Newton per square metre (in turn, a Newton is the force required to give a 1 kilogram mass an acceleration of 1 metre per second per second.) The Pascal is quite a small unit of pressure, so we often use KiloPascals (kPa), equal to one thousand Pascals. 101.325 kPa equals one atmosphere. The Bar is widely used in industry, and is still often used to specify the pressure in compressed gas cylinders, so many gas regulators are calibrated in Bar. One Bar is 100,000 Pa, and for most practical purposes can be approximated to one atmosphere (more precisely, 1 Bar = 0.9869 atm). The original units of pressure were the Torr (named after Torricelli.) This is the pressure produced by a column of mercury 1 mm high, and equals 1/760th of an atmosphere. Pounds per square inch (psi) is a common oilfield unit of pressure in British or American (USA) dominated operations. One atmosphere is approximately 15 psi.


6-3

Formation Pressure Concepts

Normal Pore Pressure Rock is grain supported

Pore fluid pressure is hydrostatic

Fluid density: 10.00 lb/gal Hydrostatic Pressure: 5190 psi

Figure 1: Normal Pore Pressure

6-4


Formation Pressure Concepts Absolute and Gauge Pressure The letters g and a often printed after pressure measurements refer to gauge or absolute pressure. Since atmospheric pressure (roughly 14.7 psi and 1.013 bar) is relatively constant it is often ignored in pressure work, and values are recorded as gauge pressure above atmospheric pressure. Absolute pressure includes atmospheric pressure. Calculation Methods Simple equations can be used to calculate pressures and pressure gradients using oilfield units. Pressure (Psi) = ppg x 0.0519 x TVDft

Using SI units: Pressure (Bar) = gm/cc x 0.0981 x TVDm

The resulting pressure may be expressed in reports or drawn on logs as: • Pressure:

psi, bar

• Pressure Gradient:

psi/ft, bar/m

• Pressure Gradient EMW: ppg, S.G., gm/cc When computing expected normal pore pressures the average density of formation fluids must be known. Offshore, the pore fluids are initially deemed to be the same as the sea water, whilst onshore a sample of formation water may be obtained. With depth however, the pore fluid density will change. Salty and fresh water horizons may be encountered, from normal environmental changes or because of later diagenesis and variations in geothrmal gradient will cause changes to salt water densities. The nature and extent of these fluid density changes may be detected from log evaluation or from samples collected from MDT and DST tests. Hydrocarbons will also alter the normal fluid gradients and can be detected by routine wellsite geological and mudlogging operations. The calculation of normal pore pressure begins at sea level offshore and water table onshore.


6-5

Formation Pressure Concepts • Fresh water:1.0 S.G. or 8.33 lb/gal • North Sea water:1.04 S.G. or 8.66 lb/gal

Depth below Flowline - m

25

Seawater Density 1.04 g/cc Sea Bed Pore-water Density 1.04 g/cc

325

Depth 0 325 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500

Fluid density Pore Pressure bar 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04

30.61 38.26 48.46 58.66 68.87 79.07 89.27 99.47 109.68 119.88 130.08 140.28 150.49 160.69 170.89 181.09 191.30 201.50 211.70 221.90 232.10 242.31 252.51

PPG bar/m 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10

PPG EMW: g/cc 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04

Pore Pressure Gradient EMW - g/cc 1

1.1

1.2

1.3

1.4

1.5

0

500

1000 Dep th - m

0 MSL

1500

2000

2500

3000

Figure 2: Normal Pore Pressure Gradient Calculation

Formation Balance Gradient Once the expected normal pore pressure has been calculated, the mud density required to balance this pressure needs to be calculated. Offshore, the required density will be less than the average density of the pore fluids because the mud column is longer than the formation fluid column. Onshore, the situation will vary with the relative positions of the mud return flowline and the effective head of water. For example, offshore the top of the mud column is at the return flowline, normally a few meters below the rig floor level. This may be 30m or so above Mean Sea Level which is the top of the formation fluid column. At shallow depths this difference in height can be significant and can lead to extensive overbalance in the early part of the well.

6-6


Formation Pressure Concepts Sometimes the effective head of formation fluids may be greater than the height of the mud column. This can occur onshore where aquifers may be drilled that outcrop at a higher elevation than the rig. In this case the Normal Formation Balance Gradient, (NFBG), will be greater than the Normal Pore Pressure Gradient, (NPPG). Where oil and/or gas are part of the fluid column, the normal hydrostatic pressure will increase at a rate consistent with the particular fluid type. This will lead to a stepped pressure/depth plot. The slope of each individual segment of the plot will be constant. This pressure gradient is a measure of the rate of pressure change over depth and will be constant where the fluid density is constant. Where oil, water and gas are present the mud density gradient required to balance the three fluid pressures at depth will be an average gradient of all the individual fluid gradients, depending on the lengths of the columns. Remember that Pressure Gradients and Equivalent Fluid Densities are average values from the point of interest back to a pre-defined starting depth such as flowline, rig floor or sea level. Mostly we reference pressure gradients to flowline in order to have a direct comparison with mud density.

Depth

0 MSL

25

Seawater Density 1.04 g/cc Sea Bed Pore-water Density 1.04 g/cc

325

Fluid density Pore Pressure bar

0 325 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500

1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04

30.61 38.26 48.46 58.66 68.87 79.07 89.27 99.47 109.68 119.88 130.08 140.28 150.49 160.69 170.89 181.09 191.30 201.50 211.70 221.90 232.10 242.31 252.51

PPG PPG FBG bar/m EMW: g/cc EMW: g/cc 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10 0.10

1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04 1.04

0.9600 0.9750 0.9880 0.9967 1.0029 1.0075 1.0111 1.0140 1.0164 1.0183 1.0200 1.0214 1.0227 1.0238 1.0247 1.0256 1.0263 1.0270 1.0276 1.0282 1.0287 1.0292 1.0296

Normal Formation Balance Gradient EMW - g/cc 0.9400

0.9600

0.9800

1.0000

1.0200

1.0400

0

500

1000 Depth - m

Depth below Flowline - m

1500

2000

2500

3000

Figure 3: Normal Formation Balance Gradient Calculation


6-7


Formation Balance Gradient Flowline

Air gap ill Dr ing Fl uid ad Gr i en

Drilling Fluid

t

Mean Sea Level Formation Fluid

Water Table

Fo

rm atio nF luid

Gr ad

ien t

Required Drilling Fluid Gradient less than Formation (Pore) Pressure Gradient

Figure 4: Formation Balance Gradient When multiple fluid densities are present in the rock, because of changes in geothermal gradient, variations in fluid type or because of stratigraphic changes a cumulative approach is taken to the normal pore pressure calculation. Normal Pore Pressure Gradient, or (NFBG), is averaged from the point of interest back to the flowline.

D

A

Individual fluid gradients

A A

Average gradient of fluids A+B+C

A+B B C

A+B+C

Figure 5: Multiple Fluid Densities

6-8


Formation Pressure Concepts Effective Circulating Density When the drilling fluid is being circulated extra pressure is created in the annulus due to the frictional effects of the borehole and drillstring. This pressure is part of the total standpipe or pump pressure recorded on the standpipe pressure gauge on the rig floor. Until recently this extra pressure has had to be calculated using one of the hydraulics models such as Bingham or the Power Law. Since the drilling fluid is flowing along the borehole the annular pressure losses are a maximum at total depth and a minimum at the surface. The bottom hole circulating pressure is the sum of the hydrostatic pressure and the total annular pressure losses. Effective Circulating Density, (ECD), is this pressure expressed as an average pressure gradient and related to an equivalent fluid density. As the value of the annular pressure losses reduces towards the surface, so the ECD also reduces and approaches the drilling fluid density. ECD is normally calculated at: • Total Depth • Casing Shoe • Weakest Point (if lower than casing shoe)

Mud pump Mud pit

Casing & cement Drill pipe Annulus

Drill bit

Open hole

Drill collar

Figure 6: Circulation System


6-9

Formation Pressure Concepts ECD is important in well planning and whilst monitoring real-time drilling operations. Casing seat selection will be influenced by the ECD-Fracture realtionship. When drilling HPHT wells there can often be a very small drilling window between the mud weight and the fracture gradient, into which the ECD has to be positioned. It is not unusual for loss-gain scenarios to be present where the hydrostatic mud weight is insufficient to balance the pore pressure but the ECD is enough to fracture the formation. Setting an extra casing string or abandoning the well may be the only alternatives. As mentioned above, until recently ECD had to be estimated from calculating the value of the annular pressure losses using one of the hydraulics models. However, these estimations are not always accurate enough since the effects of such variables as cuttings, drillstring rotation, barite sag, inclined boreholes and modern drilling fluids are rarely modelled adequately. If it is important to have very accurate estimations of ECD then an MWD Pressure-While-Drilling tool need to be used. This has external pressure transducers that measure annular pressures directly and thus enable real-time estimates of ECD to be made.

Figure 7: Effective Circulating Density

6-10


Formation Pressure Concepts It is important that the ECD is compared with the fracture pressure at the weakest point in the borehole, as well as at T.D. The weakest point is often taken as the casing shoe depth since sedimentary rocks tend to become stronger with depth of burial because of compaction. However, the casing is normally set in strong, impermeable formations to ensure an adequate cement job around the shoe; it is not inconceivable, therefore, that weaker rocks, such as poorly cemented sandstone stringers, might be present at deeper depths. This will potentially lead to fracturing, lost circulation and differential sticking problems if mud weights and ECD values are high. Measurement of ECD with a PWD tool will help identify problems at an early stage. It should be remembered that, when drilling ERD or long horizontal wells, ECD will continue to increase as the well is extended (because the length of the annulus will be increasing), whilst pore pressures and fractures may remain relatively constant.

Overburden Pressure Overburden Pressure is computed at the wellsite since it is an input parameter to Fracture Pressure calculations and also provides a means of quantifying pore pressure studies. Overburden Pressure is the total pressure acting on the rock and is produced by both fluid and rock matrix pressures. It may be defined as: S=M+P Where S = Overburden Pressure M = Matrix Pressure P = Pore Pressure It is necessary to know the average bulk density of the formation in order to compute Overburden Pressure. Normally this is broken into like sections and cumulatively calculated. Obtaining values for rock bulk density can be difficult and depends upon the availability of suitable data. Available data sources are: • • • •

Wireline Formation Density Log MWD Formation Density Log Sonic Log Cuttings Density


6-11

Formation Pressure Concepts The most accurate of these are the wireline/MWD data sources since these are downhole measured values of rock properties unaffected by drilling processes. The Formation Density Log provides information on rock bulk density directly. Unfortunately density logs are not usually available over the whole well, being mostly reserved for reservoir sections. Even MWD versions are not normally run in the sections. In the absence of density log data, calculating bulk density from sonic log data is an option. The sonic log again provides downhole measured values of rock properties, in this case interval travel time, (∆t), in µsec/ft or msec/m. Bulk density has to be derived from porosity which has firstly to be calculated from the interval travel time. Calculation of cuttings density is least accurate method of evaluating rock bulk density. The mudloggers are able to measure cuttings (shale) density which is then used as an aid in pore pressure evaluation. Since undercompaction of clays and shales is an important mechanism for the production of overpressures, plotting the trend of changes in shale density with TVD can identify undercompacted, and hence potentially overpressured, zones. Since they are looking at trends any inaccuracy in the actual cuttings density values is not a major problem as long as drilling and methodology remain consistent. Measured values of cuttings density are not especially accurate, and this is a problem if we use the data for overburden gradient calculations. Methods of measuring cuttings density are: • Single Solution • Multi Solution • Pycnometer The single and multi solution methods use the Archimedes Buoyancy Principle to measure density by immersing the cuttings in fluids of known density. The single solution method uses two partially miscible fluids (such as zinc bromide and water) in a graduated cylinder. The heavier fluid is added first followed by a small quantity of water. The boundary between them is stirred to produce a gradational density between the fluids. This process is repeated until the graduated cylinder contains a fluid of variable density from top to bottom. Glass beads of known density can be placed in the column to help obtain a linear gradient. Multiple solutions of known density fluids can also be used. Here the cuttings are immersed in the fluids (in a wire basket) and they will either float or sink. The density of the cuttings can be estimated between two fluid densities.

6-12


Formation Pressure Concepts Bulk density values obtained from cuttings are usually too low, reflecting surface tension characteristics. The drilling process will also influence the results since the cuttings have been damaged by the bit and carried to the surface by the returning drilling fluid. The action of the fluid and the bit will perhaps have changed some of the inherent rock properties, including bulk density. The use of cuttings density values for the construction of overburden gradient curves should be restricted to those occasions when no in-situ measured values of bulk density are available. The pycnometer method requires the use of the mud balance and a bulk volume of cuttings. The cup is filled with sufficient cuttings (with the lid attached) to read the density of fresh water (8.34 ppg, 1.0 S.G.). Fresh water is then added to fill the cup, (with the lid attached). The new density (W2) is measured. A comparison of the two density readings with reference to the density of fresh water allows the bulk density of the cuttings to be determined as in the formula below.

8.34 Bulk Density (g/cc) = --------------------------16.68 – W 2

Bulk Density from the Sonic Log Bulk density may be obtained from the sonic log where Wireline or LWD density log data are poor or absent. The technique involves first calculating the porosity and then using the formula below to calculate the bulk density. Porosity may be calculated from sonic travel times (∆t) using the Wyllie time-average formula: ( ∆t – ∆t m ) φ = --------------------------( ∆t f – ∆t m ) Where: ∆t= Travel time at the point of interest ∆tm= Matrix Travel Time ∆tf= Fluid Travel Time


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Density (g/cc)

∆T (µsec/ft)

Sandstone (Quartz)

2.65

55

Limestone (Calcite)

2.71

48

Dolomite (Dolomite)

2.87

44

Anhydrite

2.93

52

Salt (Halite)

2.04

67

Gypsum

2.35

50

2.5-2.8

47-170

Fresh Water

1.00

218

Salt Water

1.03

189

Lithology/Fluid

Clay/Shale

Figure 8: Rock, Mineral & Fluid properties Bulk density, ρb, is defined as: ρ b = φρ f + ρ m ( 1 – φ ) Where: ρb = Bulk Density gm/cc ρf = Fluid Density gm/cc ρm = Matrix Density gm/cc φ = Porosity % Bellotti & Giacca (1978) published an empirically derived formula to determine porosity from sonic log data where there is difficulty in establishing clay matrix densities or travel times. ( ∆ t – 47 ) ρ b = 2.75 – 2.11 ⎛ -------------------------⎞ ⎝ ( ∆ t + 200 )⎠

6-14


Formation Pressure Concepts Pressure may be calculated in the same manner as for Normal Pore Pressure and recorded in imperial or SI units. Overburden gradient is normally plotted with reference to the return flowline to maintain compatibility with mud density information. Offshore the gradient will be very low initially due to uncompacted sediments and the sea water and air gap influences. Onshore with more compacted rocks, the OBG will often approach a straight line at an average gradient of around 2.3 gm/cc Equivalent Fluid Density. The average density of a thick sedimentary sequence approaches 2.3 S.G, which is equivalent to about 19.2 lb/gal or 1.0 psi/ft. It was commonplace in earlier times to assume a constant overburden gradient of 1.0 psi/ft and few actual calculations were made. In offshore drilling environments however the average density of the sedimentary sequence is much less than this because of the seawater cover, air gap (when plotting overburden gradient with reference to the flowline) and relatively low compaction rates, compared with onshore situations. If the data is to be used in pore pressure estimations or fracture pressure calculations then accurate calculations of overburden pressure are required.

MSL Seawater Density 1.04 g/cc Sea Bed Rock Bulk Density 1.95 g/cc

Rock Bulk Density 2.05 g/cc




25

Depth Bulk Density Overburden Pressure OBG bar EMW: g/cc 0 325 1.04 30.61 0.9600 400 1.95 44.95 1.1456 500 2.05 65.06 1.3265 600 2.05 85.18 1.4471 700 2.05 105.29 1.5332 800 2.05 125.40 1.5978 900 2.05 145.51 1.6481 1000 2.05 165.62 1.6883 1100 2.15 186.71 1.7302 1200 2.15 207.80 1.7652 1300 2.15 228.89 1.7948 1400 2.15 249.98 1.8202 1500 2.15 271.07 1.8422 1600 2.15 292.17 1.8614 1700 2.15 313.26 1.8784 1800 2.15 334.35 1.8935 1900 2.2 355.93 1.9096 2000 2.2 377.51 1.9241 2100 2.2 399.10 1.9373 2200 2.2 420.68 1.9492 2300 2.25 442.75 1.9623 2400 2.25 464.82 1.9743 2500 2.25 486.89 1.9853

Overburden Gradient EMW - g/cc 0.0000

0.5000

1.0000

1.5000

2.0000

2.5000

0

500

1000

Depth - m

Depth below Flowline 0

1500

2000

2500

3000

Figure 9: Overburden Gradient Calculation


6-15


Figure 10: Overburden Gradients

6-16


Pore Pressure Detection Introduction Evaluation of pore pressure is limited by current technology and the rocks themselves. Direct pressure measurement using Wireline RFT/MDT type tools or Drillstring Pressure tests can only be made in permeable formations such as sands and some carbonates. No direct readings can be made in impermeable formations such as shales. Whilst kicks or blowouts are unlikely to occur in shales because of the limited permeability, severe drilling problems can result from drilling close to or underbalance. Contained permeable formations within shales could lead to kicks or blowouts if the pore pressure profile within shales is not understood. Most indirect detection techniques are based around the Compaction Disequilibrium (Rapid Loading) model for clays since this produces a gradual increase in pore pressure with depth (Transition Zone) which can, hopefully, be recognised and evaluated before an underbalanced condition exists. Quantification of pore pressure can be made by evaluating behavioural trends in normal pressured situations and looking for diagnostic changes. Other causes of pore pressure, particularly those that require a better seals, such as aquathermal pressuring, gas generation or lateral transfer will require recognition of the seal and identification of anomalies when drilling through the seal such as drill breaks, increases in background gas and connection gas and borehole stability problems. Quantification of pore pressure in these cases is difficult and normally requires comparison of drill rate, gas readings etc. with drilling fluid characteristics.

Methodology Compaction disequilibrium in shales can be recognised by a long pressure transition zone. In the North Sea for example there may be many hundreds of metres of gradually increasing pore pressure in Tertiary clay sections from the onset of overpressure to the point of maximum development. It is possible to monitor the increase of pore pressure with depth whilst still maintaining mud overbalance and making the required changes to mud density before the point of equilibrium with the static and dynamic (ECD) mud pressure. The techniques available are:

Rate of Penetration (ROP) When drilling a normally pressured claystone/shale sequence with a constant mud density, ROP would normally be expected decrease with depth. This is due to compaction and increasing bottom hole differential pressure. The compacting rock will become denser with depth and be more difficult to drill. If a constant


7-1

Pore Pressure Detection mud weight is used differential pressure on the bottom of the hole will increase making it more difficult for drill cuttings to be released into the returning mud stream. Roller cone bits are particularly sensitive to differential pressure; PDC bits less so. A pressure transition zone will tend to make drilling easier because of the trapped water reducing compaction and the increase in pore pressure reducing differential pressure; again roller cone bits will tend to show this effect more readily than PDC bits which will not slow down as much when drilling a normally compacting section or speed up as much when drilling the pressure transition zone. Significant variations in ROP should always be investigated. They may represent the first indications of changing formations, of developing drilling problems or drilling through a pressure transition zone. It is necessary to evaluate all the possible causes of ROP variations before reporting any pore pressure changes. As Sir Arthur Conan Doyle’s fictional detective, Sherlock Holmes, said: “When you have eliminated the impossible, whatever is left, however improbable, must be the truth”.

Factors affecting ROP include: • Rock Type • Bit Type • Dulling Bit • WOB • RPM • Hole Size • Pump Pressure • Bit Hydraulics • Mud Weight/ECD

7-2


Pore Pressure Detection

Depth

Increasing Differential Pressure with depth when mud weight & pore pressure gradient remain constant

Differential Pressure

Pressure Figure 1: Differential Pressure

Drilling Exponents (Dxc) A number of mathematical models have been developed to normalise the drilling rate to a standard set of conditions and to filter out the lithological and drilling engineering variables. This produces a dimensionless drillability index which indicates whether the rock is becoming easier or more difficult to drill. Drilling into a pressure transition zone with a constant mud weight would be expected to result in easier drilling; all other things being equal. The drilling exponent (Dxc), described below, has been the industry standard tool for a number of years but is not the only one. Geoservices and AGIP developed the SIGMA Log to provide better results in mixed lithologies, including carbonates, and Baker Hughes developed the Drilling Model in order to better reflect the way in which PDC bits drill pressure transition zones.


7-3

Pore Pressure Detection Nevertheless, it should be remembered that the Dxc is designed to work with roller cone bits drilling vertical holes through pressure transition zones in undercompacted clays and shales. Outside of these parameters use of the Dxc should proceed with extreme caution and results verified with other techniques. D-exponent The D-exponent was initially developed by Bingham in 1965 and included some, but not all, of the main influences on ROP when drilling with a roller cone bit. Bingham (1965) RW d --= a ⎛ -----⎞ ⎝ B⎠ N Bingham’s D-exponent was refined by Jordan and Shirley the following year. They added constants and solved Bingham's original equation for "d", and also added log functions. The most important change made by Jorden and Shirley, however is that they let Bingham's matrix strength constant, "a", be equal to 1. This solved the problem of attempting to define a value for rock strength when computing d, but means that changes in formation type will cause shifts in the dexponent plot which have to be interpreted by the operator. Jorden and Shirley (1967) R-⎞ ⎛ log --------⎜ ⎟ 60N d = ⎜ ---------------------⎟ 12W-⎟ ⎜ log ----------⎝ 10 6 B⎠ Where:

7-4

R

= Penetration Rate (ft/hr)

N

= RPM

a

= Matrix Strength Constant

W

= Weight on Bit (lbs)

B

=Hole Size (ins)

d

=Drilling Exponent


Pore Pressure Detection In order to accommodate changes in ROP caused by variations in mud density, Rehm and McClenden proposed the following correction in 1971. This is referred to as the corrected drilling exponent, or Dxc. Rehm and McClenden (1971) Normal FBG Dxc = d ⎛ -------------------------------⎞ ⎝ ⎠ ECD Dxc is normally calculated at regular intervals at least every meter, or 5 feet and plotted against TVD on a logarithmic scale. This is done to help make it possible to use straight trend lines for evaluation since, on a linear scale the normal compaction trend line in clays would be a curve, (similar to the overburden gradient curve). Values of Dxc range from about 0.5 to 3.0, and show increasing values as drilling becomes more difficult. Easier drilling, as found when penetrating the transition zone to abnormal pressure in claystones, produces lower values. Interpretation of Dxc requires the early establishment of a normal formation compaction trend line to which Dxc values are compared. If the formation remains normally pressured then Dxc values, in claystone, should remain on or near the normal trend line. Any variation to the left, (lower values), may indicate a transition zone. Much skilled interpretation is required to be done by the operator, however, since not all the drilling parameter variables are included in the Dxc equation, and those that are do not work perfectly. Changes in lithology will also cause shifts in the Dxc plot because no matrix strength constant is included. Major changes in rock type will cause obvious shifts which can be ignored (Dxc is responding to claystone compaction only), but interbedded or mixed lithologies will cause scatter of data points making interpretation difficult. Potential overpressured zones can only be recognised from the Dxc by comparing the behaviour of data points in a claystone sequence against the normal compaction trend line for claystone. Apart from lithology, the other major causes of trend line shift are: • Casing Points (hole size; BHA changes) • Bit Changes • Bit Types • Dulling Bits • Major Changes to Mud Properties


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Pore Pressure Detection • Changes to Mud Hydraulics • Borehole Inclination All of the above factors will require the operator to make changes to the normal

Figure 2: Drilling Data Plot compaction trend line in order that proper evaluation be made. It should also be realised that the normal compaction trend line will still be a curve, even when plotted on logarithmic paper, and that the early, shallow trends established in the upper parts of the borehole will need to be steepened as drilling proceeds. When, and by how much, to steepen trends requires skilled and experienced operators otherwise significant errors can be introduced.

7-6



Figure 3: Dxc Plot


7-7

Pore Pressure Detection Quantitative assessment of Dxc is possible by comparing the actual values to those that would apply on the normal trend line at that depth. The Ratio Method compares the actual and expected values of Dxc multiplied by the Normal Formation Balance Gradient to estimate the actual FBG. Dxc Ratio Method: Dxc n FBG actual = NFBG ⎛ ------------⎞ ⎝ Dxc o⎠ Where:

7-8

FBGactual =

Actual (estimated) Formation Balance Gradient

NFBG

=

Normal Formation Balance Gradient

Dxco

=

Dxc Observed Value

Dxcn

=

Dxc Normal Trend Value



Dxc Ratio Method

Normal Shale Trend Line

Sandstone

Equivalent FBG Lines ppg 11

10

Depth

17 15 13

Dxcn x N.FBG = FBGo Dxco

Pore Pressure = 12 ppg

Dxc semi-log scale

Dxco

Dxcn

Figure 4: Dxc Ratio Method


7-9


Figure 5: Dxc Interpretation Problems

7-10


Pore Pressure Detection Borehole Behaviour Drilling a transition zone will normally result in borehole instability which can be detected by observing a number of drilling parameters. Drilling close to balance or even underbalanced may be possible in clays due to their lack of permeability. Whilst a kick or blow out may not happen immediately, sloughing, spalling and general borehole instability will result. Increased torque, drag and overpull are all signs of potential abnormal pressure, though they could also indicate mechanical or other formation problems.Whilst the well may not kick, the borehole walls may be pushed inwards due to the pressure imbalance producing large, curved cavings in much greater volume than during normal drilling. Typical these are long, curved, twisted, with concave cross-section, very distinctive from normal cavings. They are sometimes referred to as helicopter blade shaped cavings.

Front

Side

Front

May be striated

Side

Scale

O.5" to 1.5"

Delicate shape

Blocky Rectangular Shapes

Typically cracked

Plan View

Plan View

Concave Profile A Typical shale caving caused by underbalanced drilling

B Typical shale caving produced by stress relief

Figure 6: Pressure Cavings


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Pore Pressure Detection Formation Gas Evaluation The mud logger's gas detection system can also play a vital role in pressure evaluation. Background gas values would normally decrease with depth when drilling a normally pressured claystone sequence because of compaction, increased differential pressure and reduced ROP. Drilling a transition zone usually leads to a stabilization or slight increase in background gas as the pore pressure increases. As a balanced condition approaches a combination of the loss of ECD when the pumps are turned off, and swabbing pressure when the string is pulled up during connections and other off bottom conditions can lead to a small amount of gas bleeding into the borehole. When the pipe is returned to bottom and pumping resumed a balanced condition exists once again. The gas influx however will be circulated to the surface and detected in the mud logging unit roughly one lag time after pumping recommenced. The positive detection of this Connection Gas is a sure indicator that a near balance condition exists with respect to the current mud weight, since the loss of ECD and any swabbing pressure reductions produced during the short time of the connection are likely to be fairly small. Connection gas peaks usually arrive at the surface one lag time following resumption of pumping, but may come from a permeable zone near to but not at the bottom of the hole, and therefore slightly before the normal expected bottoms up time. Similar gas peaks will occur following trips (Trip Gas) but since the trip has been ongoing for a much longer time interval (many hours perhaps) the significance of trip gas is not so great. Nevertheless care needs to be taken with detection and evaluation of trip gas peaks since a significant increase in value may also indicate pore pressure increase. The increased use of top drive rotary systems has lead to increased drilling efficiency and enhanced safety (ability to circulate more readily than with kelly systems). However since drilling proceeds with stands of pipe rather than with singles only one connection is made per stand with a top drive compared with three per stand when using a kelly system. Thus pressure evaluation using connection gas may not be so effective with top drives. Some operators perform dummy connections or long connection tests (LCTs) each 30ft (10m) when approaching known pressure transition zones to simulate connection gas.

7-12



Figure 7: Background & Connection Gas


7-13

Pore Pressure Detection Gas Ratio Analysis Analysis of gas ratios may also be able to help in the detection of overpressures, particularly where compaction disequilibrium is not the dominant mechanism. Holm (1998) has suggested that data from several HPHT wells drilled in the Central Graben of the North Sea shows gas anomalies with the onset of overpressure. Increasing background and connection gasses are observed in the transition zone but there is also an increasing wetness to the gas as the very high pressures are approached. Holm suggests that the gas is migrating from the Jurassic (Kimmeridge Clay) source rocks on an episodic basis as micro fractures occur with very high pore pressures within the source rocks caused by gas generation and fluid expansion. As the gas migrates away from the source rocks then it becomes increasingly drier as the lighter gasses are more mobile and thus will travel further. Gas within the Lower Cretaceous rocks such as the Rodby, Hydra, and Herring Formations show very similar gas ratios to the Jurassic source rocks whereas the overlying Herring Formation has much different ratios indicating generally drier gas.

Shale Density Evaluation of drill cuttings density, whilst not accurate enough for overburden gradient calculation is useful to identify clay undercompaction. A plot of shale density against true vertical depth can pick out transition zones very effectively, by looking for areas of lower than expected density. The following diagram illustrates the procedure. The overpressured zone has lower than expected bulk density values. The minimum bulk density value (which represents the maximum overpressure) would normally be expected at a much shallower depth, the Equilibrium or Equivalent Depth, which can be found by drawing a vertical line from the depth of interest to the intersection with the normal compaction trend line.The Equivalent Depth and the depth of interest both have the same bulk density values and hence the same value of matrix stress (effective stress). This type of plot can be used to help identify overpressured by qualitative means (looking for low density anomalies) but also quantitatively using Terzaghi’s relationship: S overburden pressure = σ effective stress + P pore pressure

7-14


Pore Pressure Detection Since the effective stress is the same at both depths we can substitute the value at the equivalent depth for that at the depth of interest in order to calculate the pore pressure. The effective stress at the equivalent depth can be calculated because we know the overburden pressure and the pore pressure (it’s normal). P = S–σ

Figure 8: Shale Density

Geothermal Gradient Abnormally pressured zones will usually cause a disturbance to geothermal gradient since the trapped water is a more effective insulator than rock matrix


7-15

Pore Pressure Detection material. A cooling effect will be seen above the overpressured zone as the escaping heat is trapped within. It is very difficult to measure formation temperature, and in any case equilibrium is disturbed by the drilling process. Mud temperature though is thought to increase at the same rate as formation temperature as the borehole gets deeper and the mud comes into contact with hotter rocks. A plot of mud temperature against true vertical depth may pick out the cooling effect above and the higher gradient within the overpressured zone. A temperature probe situated in the mud return flowline or the header box behind the shale shakers will continuously measure the temperature of the returning mud. This Temperature Out measurement is the basis of the evaluation. A plot of Temperature Out should show gradually increasing values according to the local geothermal gradient. As the pressure transition zone is approached a reduction in this gradient should be observed. It may, in exceptional circumstances lead to lower mud temperature readings. On entering the actual overpressured zone the geothermal gradient increases to a much higher value than the normal trend for the area. Underneath the overpressured zone, if the pore pressure declines to near normal, a normal geothermal gradient is re-established. This reduction in geothermal gradient occurs above the overpressured zone and therefore provides some advanced warning of high formation pressures below. It is the only technique available that can be used a s a predictive tool. All other techniques require us to be in the overpressured zone observing some change in behaviour of drilling or geological data. Whilst overpressured zones can be identified qualitatively by this method, little can be done to make any quantitative assessment as to the size of the overpressure. Raw flowline temperature data is subject to fluctuation and error from drilling practices. Changes in surface temperature caused by pit transfers, mixing mud, adding water or from natural diurnal ambient temperature variations (onshore) will lead to difficulties in the establishment of trends and the interpretation of the data. Deep, cold water in offshore drilling situations can lead to substantial cooling of the returning mud which may mask any heating that has been applied. Riser cooling may, though, be fairly consistent and, if not drilling in extreme situations, may not have a discernable effect on interpretation. Tripping, and other non-circulating time will lead to variations in mud temperature. The mud will heat up in the bottom part of the borehole, cool in the marine riser or conductor pipe and in the mud tanks and take some time to reach temperature equilibrium on resumption of circulation. Long trips and short drilling intervals will lead to a very segmented plot of raw flowline temperature data.

7-16


Pore Pressure Detection Some of these problems can be overcome by calculating and plotting lagged temperature difference, (∆T). With a dual probe system, the temperature of the mud is measured in the suction pits as well as at the flowline and thus the actual heating that has been applied to a particular packet of mud can be measured. Any surface influences with therefore be negated. End-to-end and trend-to-trend plots of flowline temperature data may also help in interpretation. With MWD tools, downhole measured values of mud temperature may be obtained which will overcome problems of riser cooling.

Figure 9: Geothermal Gradient


7-17


Figure 10: Cooling Effect

Wireline and MWD Logs Downhole measured data from petrophysical logs provides powerful back up data for overpressure detection. Wireline data is only available after drilling but will confirm theories established from drilling and logging parameters, whilst MWD is available real-time alongside traditional data.

7-18


Pore Pressure Detection Resistivity, Density and Sonic logs are the most useful, all providing information on compaction and porosity for use with the rapid loading model. Care must be taken when using resistivity data since changes in pore water density will change normal pore pressure gradients which should not be confused with abnormal pressure effects. Resistivity Logs In a normally compacting claystone sequence, formation resistivity values should generally increase as the rock becomes less porous. A pressure transition zone will, therefore, tend to show decreasing values of resistivity as increased porosity allows the more effective transmission of electrical signals.

Figure 11: Resistivity Log


7-19

Pore Pressure Detection As with Dxc, a normal trend line can be established for claystone and values of resistivity compared to it. Caution needs to be taken though as variations in pore fluid type will cause shifts in the normal trend. For example, changing from fresh to slightly salty pore water will cause a reduction in resistivity values which may lead the operator to suspect, erroneously, that an overpressured zone was being penetrated. Assuming that a normal trend can be established, Eaton's method can be used to quantify changes in pore pressure from resistivity data. This is a combination of the Ratio Method and Equivalent Depth Method that uses data only from the depth of interest. Eaton's Method: R o 1.2 P = S – ( S – P n ) ⎛ ------⎞ ⎝ R n⎠ Where: P

=

Pore Pressure

S

=

Overburden Pressure

Pn

=

Normal Pore Pressure

Ro

=

Observed Resistivity value

Rn

=

Normal trend Resistivity value

1.2

=

Exponent (variable)

Sonic Logs Sonic log data is some of the best data available for evaluation of formation pressure in claystone sections. The log measures rock compaction and records interval travel time in m sec/foot. A normally compacting claystone shows increasing density with depth and therefore increased sonic velocity and lower travel times. Again, a normal compaction trend line can be established and compared to actual data. Potential overpressured zones will show as areas of higher than expected m sec/foot. The equivalent depth method is usually used to quantify changes to pore pressure, assuming that the formation is constant and represents a continuous sequence back to the equivalent depth.

7-20


Pore Pressure Detection Equivalent Depth Method: P = S–σ Where: P

=

Pore Pressure

S

=

Overburden Pressure at depth of interest

σ

=

Effective Stress (matrix pressure) at Equivalent Depth

The Equivalent Depth method is used by drawing a line vertically from the point of interest until it intercepts the normal compaction trend line, thus defining the Equivalent or Equilibrium Depth. The pore pressure and overburden pressure values at this depth are used to define the effective overburden pressure, σ1, which, assuming Compaction Disequilibrium to be the dominant cause of the abnormal pressure, has remained constant during burial. The value of σ1 is therefore the same at the point of interest.


7-21


10

100

200

4000

5000

D ep th

6000

7000

8000

9000

10000

11000

∆t µsec/ft Figure 12: Sonic Log

7-22


Fracture Pressure Introduction A knowledge of Formation Fracture Pressure is necessary in order to drill the well both safely and economically. The optimum mud density is sufficient to balance pore pressure but not so high that hydrostatic, circulating or surge pressures would cause the rock to fracture. Measured values of fracture pressure can be obtained from Leak-Off Tests (LOT) which are normally performed just below the casing shoe. With the well shut in, a small volume of mud is pumped at a low flowrate into the borehole. The imposed pressure within the borehole will increase as the mud is pumped and will be recorded on a pressure gauge as a linear increase above hydrostatic pressure. As the fracture pressure is approached fluid will begin to be lost to the formation and the rate of increase of imposed pressure will reduce. At the point at which the straight line increase becomes a curve, the mud hydrostatic pressure plus the imposed pumping pressure is equal to the rock fracture pressure and the test is terminated before fractures are propagated and irreparable damage is done to the formation.

Leak - Off Test Pump Stopped C D B

Gauge Pressure psi

Bleed Off

Total Pressure at B: Gauge Pressure + Mud Hydrostatic Total Pressure at C: B + Crack Extension Pressure Total Pressure at D: B=D

1 1

2

3

2

3

4

Time, minutes

BBL Mud Pumped

Figure 1: Leak - Off Test


8-1

Fracture Pressure There is a general tendency for sedimentary rocks to become stronger with depth due to compaction, so that, mostly, fracture pressure also increases with depth. This is an over simplification however since changes in lithology and pore pressure can both cause significant fracture pressure variations. In order not to have to take further LOTs, (which is both time consuming and potentially damaging to the formation), mathematical models are used to estimate variations in fracture pressure as the well is drilled. All the models used are calibrated from LOTs, causing pessimistic results when only Formation Integrity Tests (FIT) are made rather than true leak-off tests. They also suffer by being too simple in approach and by using empirically derived data that may not always have widespread geographical applicability. When used wisely however, and by skilled operators, the models give useful in-formation and a more accurate view of fracture pressure than from LOT data taken at the casing shoe.

Evaluation of Fracture Pressure In a relaxed sedimentary environment, with horizontally bedded rocks and no external tectonic stress, the forced acting on a point in the subsurface can be resolved as follows:

Effective Stress Pore Pressure Horizontal stress

Figure 2: Downhole Stresses

• Pore Pressure (P) A non-directional stress which has to be exceeded by the mud pressure if hydraulic fracturing is to be produced

8-2


Fracture Pressure • Effective Stress (σ1) This is the matrix or grain stress component of the overburden pressure and will be a vertical stress • Horizontal Stress Horizontal stresses are produced as a result of the vertical effective stress. In the sub-surface in a confined setting these can be resolved into two, mutually perdendicular, stresses. In the absence of any external directional tectonic stresses the magnitude of the horizontal stresses will be the same, but will be less than the effective stress. In order to break the rock each of the above stresses has to be exceeded by the mud pressure. The pore pressure is known from Wireline or Drillstem Tests, from indirect methods using drilling, geological and petrophysical data or as a result of the analysis of pressure during well control operations. The effective stress is computed from the difference between the overburden pressure and pore pressure. The minimum horizontal stress is the most difficult component to quantify, but is usually thought of as being related to the effective stress. Thus a stress ratio co-efficient, F, is included in most models to relate the effective stress to the minimum horizontal stress The assumptions given above provide the basis for all the commonly used models, and give the general formula: F = ( S – P )k + P Where: F = k = S = P =

Fracture Pressure Effective Stress Ratio Overburden Pressure Pore Pressure

Hubbert and Willis (1957) These authors worked on data from US Gulf Coast wells, assuming relaxed beds on the point of extensional (normal) faulting. In this case, and determined empirically, the effective stress ratio, K, is assumed to be between 1/2 and 1/3 of the principle vertical stress, σ1. Fracture Pressure is normally defined as: (S – P) F = ----------------- + P 3


8-3

Fracture Pressure Matthews and Kelly (1967) Matthews and Kelly introduced a variable stress coefficient, Ki, into the general formula as shown above. Values of Ki were obtained by back calculating from known LOT results and the establishment of regional values for future wells. F = ( S – P )ki + P It should be noted that the value of Ki is determined from the depth at which σ1 is normal, i.e. the Equivalent Depth, and that alternate calibration curves need to be established for areas outside the US Gulf Coast region.

Figure 3: Stress Ratio Co-efficient (ki)

8-4


Fracture Pressure

Figure 4: Ki using Equilibrium Depth

Eaton (1969) Eaton decided that rock deformation was elastic, and therefore linked the calculation of K to Poisson’s Ratio. Eaton’s equation for Fracture Pressure is: µ F = ( S – P ) ⎛ ------------⎞ + P ⎝ 1 – µ⎠


8-5

Fracture Pressure Where: µ = σ1 =

Poisson’s Ratio Effective Stress

Poisson’s Ratio is the ratio of the lateral unit strain to the longitudinal strain in a body that has been stressed longitudinally within its elastic limits. Eaton decided that Poisson’s Ratio for the formation of interest would be mostly controlled by depth rather than material. Different materials though have specific values of Poisson’s Ratio which can be determined by acoustic testing looking at the behaviour of shear waves and compressional waves. It is difficult however to obtain accurate values for Poisson’s Ratio in the field so Eaton’s assumption of a depth related response allows the estimation of Poisson’s Ratio values once some regional data from offset wells has been established. Unfortunately, since rock fracture pressure tends to increase with depth Eaton’s method tends to show a fairly uniform increase in fracture pressure with depth in response to gradually increasing Poisson’s Ratios. The values of Poisson’s Ratio range from about 0.25 - 0.5 (the theoretical upper limit of a liquid). Back calculating values of Poisson’s Ratio from offset data often gives values >0.5 suggesting some error has been introduced or that, perhaps in Eaton’s method, some other force is being ignored.

Other Methods Anderson et al. (1973) Having seen that fracture pressure gradients could vary considerably in different formations at similar depths, Anderson tried to find some way of putting lithological variation into his equation. Working from US Gulf Coast data, Anderson thought that the major control on rock deformation was the elastic nature of the materials, expressed by Poisson’s Ratio. Rather than assume that Poisson’s Ratio increased uniformly with depth, (as Eaton), Anderson attempted to measure it in situ by using wireline log data. He made a further assumption that elastic fracture would be primarily controlled, (in sandstones at least), by the shale or clay content. His method involves calculating the shale content from variations in porosity from density and sonic logs and using this to calculate a value for m. The method is somewhat cumbersome to use in the field, and only sand lithologies are considered. It has not, therefore, found widespread application at the wellsite.

8-6


Fracture Pressure Pilkington (1978); Cesaroni et al. (1981); Breckels and van Eekelen (1981) All of these authors were trying to find more accurate ways of determining the stress coefficient, K. The methods are related to specific basins and require extensive offset data and local knowledge to use their methods successfully.

Daines (1982) This is now one of the most widely used models, albeit with certain limitations. Daines took up the work of Eaton, as uses a similar equation, with certain key variations: • Poisson’s Ratio This is now calculated for rock material rather than depth of burial.Laboratory derived data are used, and it is necessary to equate the formation of interest to results shown in the tables given below. • Tectonic Stress Any additional tectonic stress imposed on the system and not yet accounted for can be determined from the results of LOTs and Poisson’s Ratio values obtained as above. Daines’ equation for Fracture Pressure is: µ F = ( S – P ) ⎛⎝ ------------⎞⎠ + P + σt 1–µ

Where: σt σ1 µ

= = =

Superimposed Tectonic Stress Effective Stress (S - P) Poisson’s Ratio

The superimposed tectonic stress, σt, is computed from the first LOT using values of µ derived from the tables. To calculate σt at other depths, Daines suggests a relationship with σ1 that increases uniformly with depth, provided the rocks remain in the same geological setting:


8-7

Fracture Pressure

Suggested Default Poisson’s Ratio Data Clay Wet/Soft

0.5

Claystone/Shale

Indurated

0.17

Claystone/Shale

Calcareous

0.20 - 0.28

Claystone/Shale

Sandy

0.1 - 0.14

Limestone

Hard

0.28

Limestone

Argillaceous

0.17 - 0.25

Sandstone

Moderate Cement

0.05

The above figures for Poisson’s Ratio are based on data produced by Weurker in the 1960s and are for guidance only. Offset or recently derived laboratory or log data should be used wherever possible.

Inclined Boreholes Fracture Pressure determination in inclined boreholes is more complicated and difficult to evaluate. A knowledge of the stress regime is required and also the anisotropy of the rocks. In general terms, fracture pressure will decrease with increasing hole angle and mud density requirements to prevent borehole collapse will increase. This tends to narrow the drilling window between the pore pressure and fracture pressure, especially with horizontal drilling as the ECD will continue to increase along the length of the borehole even though TVD (and therefore fracture pressure and pore pressure) remains essentially constant. Evaluation of fracture pressure in inclined boreholes is normally established by mini-frac tests and observation rather than by mathematical interpretation.

8-8


Fracture Pressure

Variation of Fracture Gradient and Minimum Mud Weight with Well Deviation

Fracture Gradient ppg

18.3

Minimum Mudweight Fracture Initiation

16.3

14.3

12.3

10.3

8.3 0

30

60

90

Well Deviation (degrees)

Figure 5: Fracture Gradient & Mud Weight in inclined boreholes The above diagram shows the theoretical variation of fracture pressure with increasing hole angle. The fracture initiation pressure is that force required to initiate new fractures. The propagation pressure is the force required to extend these fractures. In low inclination boreholes (<55o) the fracture propagation pressure, once fractures have been initiated and the original force released, is less than the original initiation pressure. As the hole angle increases the fracture initiation pressure drops below the fracture propagation pressure. The practical fracture gradient however will remain at the propagation pressure value since small fractures will only cause a slight and finite volume loss.


8-9

Fracture Pressure

Variation of Fracture Gradient with Well Deviation

18.3

Fracture Gradient

Fracture Gradient ppg

Fracture Initiation Fracture Propagation

16.3

14.3

12.3

10.3

8.3 0

30

55

60

90

Well Deviation (degrees)

Figure 6: Effective Fracture Gradient in inclined boreholes

Inclined Borehole Formula The following formula can be used to calculate fracture pressure for inclined boreholes: 2

2

F = σ 3 ( 3 – cos θ ) – ( σ 1 sin θ ) + T + P Where: σ1, σ2 and σ3 are the maximum, intermediate and miniumum stresses; θ is the borehole inclination; T is the tensile strength of the rock P is the pore pressure

8-10



Example Reporting Procedures Stag Geological Services Ltd. Reading UK

Revision A April 2008


APPENDIX 1:

Reporting Procedures

3.1 DAILY REPORTING The Morning Geological Report and the Lithlog form the basis of the Wellsite Geologists’ reporting requirements. The report, formatted as a Microsoft WORD document, covers all facets of the rig operations over a 24 hour period and an example of this is shown at the end of this appendix. The report is sent on a daily basis, seven days a week and covers the period 0600 hours to 0600 hours. 3.1.1

Daily Geological Report and Lithlog

Information displayed on the front page of the report is largely derived from the Daily Drilling Report. It is essential that no discrepancies exist between the Drilling and Geology reports, especially with respect to depths, daily footage, costs and operational activity. Pay special attention to documentation of hole problems. Obtain a copy of the Drilling Report immediately upon completion after 06:00hrs to assist completion of the relevant sections. Ensure that the Geology Report is complete within one hour of the report time as this will enable transmission to the office within 1 ½ hours of the specified report time (06:00hrs for UKCS operations). The wellsite litholog (refer to Section 2) should as up to date as possible and transmitted to the office at the same time as the Geology Report. 3.1.2

Nomenclature

A computerised web-based data and reporting transmission system which is currently provided. The listing below uses the standard nomenclature used for the data types and plots that are posted on the website, and it remains important that it is strictly adhered to for the sake of consistency and facilitating data searches. Daily Drilling Report Daily Geological Report Deviation Survey Digital Data Engineering Log Plot Information Lithlog LWD Digital Data LWD Log Plot LWD Memory Digital Data LWD Memory Log Plot MDT Data

Mud Log Digital Data Mud Log Plot Pressure Log Plot Progress Log PWD Digital Data PWD Log Plot Time v Depth Graph Welltest Data Wireline Digital Data Wireline Log Plot

Regional offices may adopt specific guidelines on file naming, and it is the responsibility of the Wellsite Geologist to clarify with the responsible Operations Geologist the exact requirement. Such guidelines should be issued in writing. The generic file naming convention should be as follows; (WELLNAME)_(Data or Report Type)_(Date or Depth) Abbreviations for Data/Report Types Daily Drilling Report Daily Geological Report Deviation Survey Digital Data Engineering Log Plot Information Lithlog LWD Digital Data LWD Log Plot LWD Memory Digital Data LWD Memory Log Plot MDT Data Mud Log Digital Data Mud Log Plot Pressure Log Plot PWD Digital Data PWD Log Plot Time v Depth Graph Welltest Data Wireline Digital Data Wireline Log Plot

DDR (Report number) DGR (Report number) SD MLEL info GL LWD_DRT LWD_LRT (500 or 200) LWD_DM LWD_LM (500 or 200) MDT MLDD MLML MLPL PWDD PWDL TDG WTD WD (Run #_ Tooltype) WL (Run #_ Tooltype)

Date Date Depth Interval Date Depth Interval Interval Interval Interval Depth Interval Interval DepthTVD Depth Depth Date Date Depth Depth

Examples For example, a memory LWD ascii data set from the “12/34-5a” between 2700m and 3100m would be labelled 12/34-5a_LWD_DM_2700-3100m. A realtime 1:500 logplot from the same well and depths would be labelled 12/345a_LWD_LRT500_2700-3100m Wireline PEX LAS data from Run 3d from the “Titan-8” well at 12115ft would be labelled Titan-8_WD3d_PEX_12115ft The mudlog from “Saturn-13” between 11000ft and 13000ft would be Saturn8_MLML_11000-13000ft

The Wellsite Geologist’s Lithlog should commence from the start of the phase with a 100 ft overlap. Mudlogging contractors should supply logs and ASCII data from the start of the phase with a 100ft overlap. LWD contractors should supply logs and ASCII data from at least the start of the drilling run with an initial 100ft overlap, though ideally data should commence also from the start of the phase (note however that slight tool component changes may complicate generation of a consistent data suite). In the event of digital communications not be possible, the Daily Geological Report, Geologists Lithlog and the Mudlog should be transmitted by fax as priority, with digital copies following resumption of communications. 3.1.3

Verbal Reporting

During weekdays the Wellsite Geologist will call the Operations Geologist in both the morning and afternoon at prearranged times to be advised by the Operations Geologist, normally 08:00hrs and 15:15hrs. Weekend verbal reporting will be as agreed with the duty Operations Geologist. 3.2

WEEKLY REPORTING

A Weekly Geological Report and Weekly Service Company Review should be prepared and issued electronically for Friday 12:00 hrs with a 06:00hrs cut-off, though this can be adjusted dependant on operations. Examples are included at the end of this Appendix. The Weekly Report should contain summaries as opposed to detailed descriptions and include the following: a) Basic well information b) Depth, previous and present, and weekly progress c) Concise operations summary d) Formation tops: prognosed, actual, nature of picks, high or low e) Brief lithology description f) Hydrocarbon shows g) Logging/coring/testing details No logs are normally required specific to the Weekly Report. The Operations Geologist will advise separately otherwise.

Daily Geological Report Well Information Well

Rig

Date

Report

DSS

ABCDEF -1

South Seas Driller

20 March 2009

32

27

RT-MSL (ft)

Water Depth

85

295 ft

Latitude

Longitude

Pred.Days

PTD (ft)

0

18,478

MD-RT (ft)

TVDSS (ft)

Progress (ft)

Hole Section

Section PTD (ft)

17,960

-8999

258

12 ¼”

17,787

Casing OD (ins)

Type

MD (ft)

TVD (ft)

30”/20”

--

600.6 ft

600.6 ft

13 3/8”

L-80 72#

3437 ft

3437 ft

Dry Hole

Test/Completion

Total

AFE

GBP 4,670,000

GBP

GBP 4,670,000

Daily

GBP 95,000

GBP

GBP 95,000

Cumulative

GBP 2,960,000

GBP

GBP 2,960,000

Projected

GBP 4,670,000

GBP

GBP 4,670,000

Costs

Present Operation Circulating hole clean & bottoms up sample from 17,960’, to comfirm 9 5/8” casing shoe setting of 17,935’ equal to 35-45’ into the Maureen formation.

Operations Summary Controlled drilled from 17,602 - 17,960’, to pick 9 5/8” casing point in the Maureen formation. Circulated sample as required.

24 Hour Forecast Circulate hole clean for 17,960’ if section TD. Pump out or POOH to 16200’ just above the Balder formation. RIH. Circulate bottoms up. Drop EMS survey barrel. Circulate 30 bbls fordacal LCM pill to bit. POOH two stands pumping & placing LCM on bottom. POOH 3 stands & pump slug. POOH taking surveys to the 13 3/8” casing shoe & take 2 x cluster shots in open hole. Circulate bottoms up & shale shakers clean. Continue to POOH & recover EMS survey barrel. Pull wear Bushings. Rig up to run 9 5/8” - 10 3/4” casing. Drilling Supervisor: K.Doyle/M. Mateyovsky

Geology Stratigraphy Formation Tops

Prognosed (ft)

Actual (ft)

MDRT

TVDSS

MDRT

TVDRT

TVDSS

High Low

Lith Log

Top Utsira sandstone

4,646

4,250

4,470

4,223

4,138

112H

Lith

Base Utsira sandstone

4,798

4,350

4,638

4,338

4,253

97H

Lith

Top Eocene

12,902

7,300

13,065

7,440

7,355

55L

MWD

Balder

16,259

8,447

16,163

8,485

8,381

66H

MWD

Sele

16,405

8,497

16,307

8,532

8,428

69H

MWD

Lista

16,999

8,700

17,100

8,790

8,703

3L

MWD

Maureen

17,705

8,941

17,877

9,056

8,970

29L

MWD

Maureen sandstone

17,757

8,959

18,000

9,101

9,012

53L

MWD

Chalk

18,228

9,120

18,449

9,254

9,168

48H

MWD

TD

18,478

9,205

18,700

9,347

9,261

MWD

Lithology Summary Interval (ft)

Rate of Penetration (ft/hr)

Total Gas (%)

Lithology

From

To

Minimum

Maximum

Average

17,702

17,890

14.50

95.00

35.00

1.00

Claystone

17,890

17,960

10.70

49.00

23.00

1.16

Claystone, Siltstone

Lithology and Show Description 17692 - 17890 CLAYSTONE and TUFFACEOUS CLAYSTONE, with INTERBEDS LIMESTONE and TUFF. CLAYSTONE (90 - 100%): predominantly moderate to dark greenish grey, moderate bluish grey, soft to firm, sub-blocky to blocky, crumbly - flakey, non-calcareous, silty to very finely arenaceous in part, tuffaceous. Also locally greyish brown, dusky brown, soft to firm, sub blocky, non-calcareous, dispersive, silty in part. LIMESTONE (Trace to 40%): pale to moderate yellowish brown, occasional pale grey, firm, blocky, crumbly, brittle in part, microxln, slightly argillaceous in part. TUFF (Trace): pale grey, very light grey, occasional speckled I mottled soft, flakey, ashy, non-calcareous, trace dispersed finely xln pyrite. SANDSTONE (Trace): very fine to occasional fine grain, moderately sorted, sub-rounded to rounded, friable, calcareous cement. 17890 - 17945 ft CLAYSTONE with INTERBEDDED SANDY SILTSTONE. CLAYSTONE (50 - 100%): predominantly dark grey to grey black, also olive black, greenish grey, firm, blocky, brittle, non-calcareous, non to slightly silty, common microlaminae black ?carbonaceous material and disseminated pyrite. SILTSTONE (0 - 50%): light grey, pale yellowish brown, firm, blocky, brittle, very calcareous, very finely arenaceous in part, grading to silty limestone. Slight trace black carbonaceous material. LIMESTONE: (trace): white, pale grey, firm, crumbly, micritic. TUFF (Trace): medium bluish grey, firm, ashy, laminated with dark gry streaks. I -1

Gas Data Interval (ft)

Total Gas

Chromatograph

From

To

Av

Max

C1

C2

C3

iC4

nC4

C5

17,702

17,890

.995

1.284

7762

160

63

10

21

-

17,890

17,945

1.16

1.279

15118

698

141

13

22

-

Est. Pore Pressure: 11.5 ppg

Mud Weight: 14.45 ppg

Mud Type: NOVADRIL

Remarks Circulated bottoms up from 17702 ft Drilled 17702 to 17712 ft Circulated bottoms up Drilled 17712 17762 ft Circulated bottoms up Drilled 17762 to 17812 Circulated bottoms up Control drilled 17812 to 17900 at 30 ft/hr Circulated bottoms up Drilled 17900 to 17945 ft Circulated bottoms up Drilled 17945 to 17960 ft Circulated bottoms up Top of Lista Formation ‘Hot Shale’ 17776 ft (-8936 ft) Top Maureen Formation from micropalaeo. 17890 ft (-8975 ft) Top Maureen from MWD GR log 17879 ft (-8971 ft)

Biostratigraphy Descriptions Samples 17700

17880 17900

Taxa Encountered Saccarnmina complanata, Cystammina globigeriniforrnis, S. spectabilis with massive Oligocene cavings Cystammina globigeriniformis common, Rzehakina epigona. Sphaerosiderite C. globigeriniformis prominent, sphaerosiderite prominent C. globigeriniformis common, sphaerosiderite dominant C. globigeriniformis dominant Cenosphaera lenticulans prominent

17910

Cenosphaera lenticularis present

17713 17760 17810

Interpretation Late Palaeocene, Lista Formation as above Basal Lista Formation. suggesting proximity to basal warm shale Basal Lista Formation warm shale microfauna earliest Late Palaeocene. Zone PM14. indicating penetration of the Maureen Formation. as above

Survey Data MDRT (ft)

Type

17,723

East (ft)

Vertical Section (ft)

Dog Leg (deg/100 ft)

-11,673.7

-6,284.6

13,259.7

0.1

9,036.7

-11,755.1

-6,329.8

13,352.7

0.3

9,059.2

-11,809.3

-6,359.8

13,414.7

0.1

Co-ordinates

INC (deg)

AZI (deg)

TVDRT (ft)

North (ft)

MWD

70.1

209.1

9,002.9

17,822

MWD

69.9

208.9

17,888

MWD

70.0

208.9

Wellsite Geologist: A. Bikey

ABCDEF-1 : WEEKLY GEOLOGICAL REPORT Friday 25th to Monday 7th March 2009 ( Delayed end-date to incorporate TD logging ) Well Report No DSS Depth Progress

: ABCDEF-1 :5 : 35.875 : 3235m MD (-3209.1m TVDSS) : 267m – Final well TD

Area Rig RT-MSL/WD

: Madejski : South Seas Driller : 25.9m / 90.1m

Last Casing

: 9 ⅝" @ 2964m

OPERATIONS SUMMARY The 9 ⅝” casing was RIH to 2843m, filling every 10 joints and breaking circulation every 500m, prior to landing out at 2964m shoe depth on 5” WDP with the hanger HOP at 114.44m. After circulating the casing volume and pressure testing the cement lines, cementation proceeded thus; • 40 bbl drill water spacer. • Launch lower dart, mix and pump 49 bbls Class “G” & 35% SiO2 at 12.8 ppg. Mix and pump 55 bbls Class G & 35% SiO2. • Displace surface lines with 10 bbls mud, observe wiper plug shear off. No losses observed. • Displace cement with 674 bbls on rig pumps. No plug bumping observed. No backflow observed, plugs holding. The seal assembly couldn’t be set and upon pulling out with the CHSART to replace the assembly, some cuttings were observed in the running tool. A mill and flush tool was RIH to clean the hanger seal area and the seal assembly rerun and successfully set, with a 5000 psi pressure-test for 10 minutes. The BOP was pressure-tested as per Dolphin procedures and the wear-bushing set prior to laying out the cement head and 12 ¼” BHA. Surface tests were then performed to the TIW valve, IBOP, kelly hose and mud manifold to 300 / 5000 psi.

8 ½” phase operations commenced with the make up of the 8 ½” phase BHA incorporating a Smith MW9342 Rock bit with 3x15 nozzles (no MWD). The assembly was RIH on 5” drillpipe to 2880m and washed down to the Top of Cement (ToC) at 2930m with 500 gpm. Shoe-track drilling commenced from 2930m with 2-15 klbs WOB, 30-60 rpm and 300-700 gpm flowrate for 1500-3200 psi SPP, making slow initial progress whilst spinning on the unbumped plug. Firm cement was drilled to 2942m followed by a successful casing pressure-test performed to 4200 psi with full returns. The remaining cement, rathole and 2m of new formation was drilled out for the LOT, this being made to 2242 psi with a conditioned 9.5 ppg mud (13.93 ppg EMW).

Drilling in the calcareous claystone of the San Carlos Marls Member continued from 2970m with 15-25 klbs WOB, 80-140 rpm and 400 gpm for 1500 psi SPP averaging a consistent 2-3 m/hr. The lithology became increasingly silty with occasional thin very fine sandstone horizons which caused the penetration rate to become more erratic. From 3071m, drill-rates increased from 3 to 9 m/hr and the drill-break was flowchecked (static) prior to circulating bottoms-up for geological samples. These confirmed the Amposta Formation limestone, the primary reservoir objective of the well, and following surface analysis and consultation with asset and operations team, an additional 10m were drilled with a second bottoms-up circulation. Further UK and Columbian discussions from the evaluation of cuttings and data resulted in drilling operations resuming using parameters of 15-25 klbs WOB, 80-100 rpm and 400 gpm for 1850-2150 psi SPP.

The well final TD was reached at 3235m MDBRT, -3209.1m TVDSS, upon instruction from UK and Colombia, at 08:00hrs, 3rd March 2005. The Tarraco Formation (Casablanca Formation regional equivalent) was penetrated at 3212m, 3186.1m TVDSS from drilling parameter and cuttings analysis, observing 2-4 m/hr drill-rates in the clastic lithology which compared to 4-6 m/hr in a basal dolomitic carbonate band. Upon circulating the hole clean, a wiper trip was made to the 9 ⅝” casing shoe – backreaming the interval 3224m to 3081m – with no hole problems noted running to TD for final circulation, Totco surveying (2° at 3235m) and POOH to surface, racking back the BHA.

Logging operations with Schlumberger wireline commenced as follows; • • •

Run 3A (PEX-HRLA-GR-HTEN) Run 3B (DSI-FMI-GR-HTEN) Run 3C (VSI-GR)

Log interval: 3235m – 2964m Log interval: 3232m – 2964m Log interval: 3230m – 1630m

Full details of the operational progress are enclosed in the file ABCDEF1_Run3_logReport.doc, attached with this report. No operational downtime was recorded. The initial wireline TD was 3239m MD with the 9 ⅝” casing shoe at 2964m.

With maximum bottom-hole thermometer temperatures of 131°C, 137°C and 143.3°C successively recorded from the three runs, a wiper trip was performed to reduce the mud temperature in anticipation of a MDT pretest program to complete the wireline evaluation program. A maximum trip gas of 17.8% was recorded from the Datalog GasWizard. Two further logging runs were performed thus ; • •

Run 3D (MDT-GR, 28 pretests) Run 3E (MDT-GR, 1 fluid sample)

Log interval: 3077m – 3203m Log interval: 3080m – 3094m

Temperatures of 148°C were recorded from the thermometers. The fluid sample was analysed on surface and upon consultation with UK and Columbia, the well was formally abandoned. Cementing operations commenced with the running of the 3 ½” stinger on 5” drillpipe. Summary concluded.

GEOLOGICAL SUMMARY

Formation Tops Ebro Sandstone

Prognosed (m) TVDS MDRT S 115.9 -90

Actual (m) TVDR TVDS MDRT T S 116 116 -90.1

High/ Low (m)

Lith/ Log

0.1L

BHA

Ebro Claystone

975.9

-950

965

965

-939.1

10.9H

Lith

Castellon Shale

2775.9

-2750

2561

2561

-2535.1

214.9H

Lith

Amposta

3230.9

-3205

3071

3071

-3045.1

154.9H

Lith

Tarraco Alcanar Conglomerate

3336.9

-3311

3212

3215

-3186.1

124.9H

Lith

3401.9

-3376

Not encountered

Cretaceous

3431.9

-3406

Not encountered

TD

3461.9

-3436

3235

3235

-3209.1

LITHOLOGY SUMMARY Alcanar Group, San Carlos Marls eqv. Member 2968m – 3071m MDBRT Calcareous and increasingly silty CLAYSTONE with thin silty SANDSTONE horizons. Increase in argillaceous SILTSTONE from 2996m to 3050m, then becoming argillaceous. 40% - 80% CLAYSTONE: Light to medium grey, minor brownish grey, soft to moderately firm, predominantly amorphous and dispersed, sub blocky, low silt content, very calcareous to marly, with traces of carbonaceous matter disseminated pyrite and rare glauconite growths, locally abundant planktonic foraminifera – occasionally pyritised, no show. (except 3002m: no visible staining, no direct fluorescence, very slow streaming yellow white / yellow green cut fluorescence with intermittent green white residual ring, no visible residue.) Becoming medium to dark grey brown, dark grey, firm to very firm, blocky to trace subplaty, earthy, slightly mottled, homogenous, very calcareous, micromicaceous with rare trace pyrite, occasional clear angular silty quartz - grading to argillaceous siltstone. 10 – 20% SILTY SANDSTONE: Medium grey with light brownish grey hues, slightly mottled, moderately firm, friable; quartz, silty to very fine, angular to subangular, elongate to subelongate, moderately sorted, calcite grading to matrix

supported calcareous argillaceous cement, very silty in parts, disseminated pyrite and rare traces of carbonaceous matter, rare ferruginous staining, micromicaceous, very poor to no visible porosity, no show. Rare fine to medium, clear and angular loose quartz grains. 10 – 60% ARGILLACEOUS SILTSTONE: Medium grey to grey brown, firm, subblocky to blocky, slightly friable, earthy, homogenous, micromicaceous and calcareously cemented, rare argillaceous matrix, common very fine sand, trace disseminated pyrite, rare trace carbonaceous specks, rarely grading to silty sandstone. Alcanar Group, Amposta Limestone Formation 3071m – 3167m MDBRT Firm packestone, highly fossiliferous biocalcarenitic LIMESTONE with variable bituminous staining. 100% LIMESTONE: Mudstone to generally packestone, common grainstone, recrystallised in parts, off white to very light grey, firm to hard, blocky, brittle in parts with angular fracture, cryptocrystalline matrix when present, dull to pearlescent, occasional discrete dark green glauconite grains, abundant forams, possible recrystallised coral debris, echinoids. No significant visible fractures, poor to no visible porosity. ( Grains formed by bioclasts and reworked limestone, recrystallised, abundant bio calcarenites and biocalciradites, well cemented, common pressure / dissolution seams lined with dark brown to black tarry organic deposits, minor stains in moldic porosity and microfractures. ) SHOWS: 3071-3080m: Traces of dark red-brown to black bituminous staining and flakes only, no visible or cut fluorescence, no odor or residue. 3080-3089m: 20-30% of grains coated with black to brown heavy/tarry organic staining, no direct fluorescence, weak to fair slow pale white streaming cut from cuttings with brown organic stains in microfractures, pale green white UV ring, no visible residue. 3089-3101m: Weak very slow pale green white streaming cut, no direct fluoresence, no UV or visible ring. Below 3101m, no significant cuts. Stain diminishes to 10-15% with rare staining from 3113 - 3122m, trace below 3122m. 3167m – 3212m MDBRT Packstone Limestone with Grainstone to very finely crystalline Dolomitic Limestone. From 3203m to 3215m, strong development of Calcarenite Limestone. 10-30% DOLOMITIC LIMESTONE: Grainstone to crystalline, light brown grey, translucent, hard, blocky and well consolidated, very fine sucrosic crystallinity with loss of original texture, trace calcite cement, grain/crystal supported, non to rarely fossiliferous with undifferentiated debris, very poor to no visible porosity, no fluorescence. Rare trace of light to dark brown intergranular staining from 3182m.

70-90% LIMESTONE: becoming increasingly fossiliferous, biocalcarenite with common recrystallisation. SHOWS: Trace only of dark brown-black bituminous staining, no live oil. No fluorescence. (From 3203m) Trace-80% CALCARENITE LIMESTONE: Cream to off white, firm, occasionally hard, friable, crumbly, coarse quartz grains and occasional dolomite. Quartz: translucent, very fine to medium, angular to subangular, subspherical, poorly sorted. Common bio- and dolomite clasts, strong calcareous cement, clast supported, trace benthonic forams. Alcanar Group, Tarraco Formation (“Casablanca Formation” Eqv Frm) 3212m – 3224m MDBRT Very calcareous, very fine to medium grained, poorly sorted glauconitic SANDSTONE gradational to calcareous sandy SILTSTONE. Glauconite in upper 3m. 10-70% CALCAREOUS SANDSTONE: Light cream brown to brown, rarely dark brown, firm to hard, blocky aggregate, fine to medium, occasionally coarse, subangular, moderately spherical, poorly sorted, strong dolomitic and calcareous cement, cement supported, minor calcareous bioclasts, common coarse glauconite grains in uppermost 3m, rare argillaceous matrix, slightly micaceous, trace pyrite, very poor to no visible porosity, no shows. Trace-80% CALCAREOUS SANDY SILTSTONE: Brown to dark brown, very firm to hard, blocky, earthy, homogenous, strong calcareous cement – dolomitic in parts, rare argillaceous matrix, common very fine sand, micromicaceous in parts. Trace-20% CALCARENITE LIMESTONE: As per previous description. Probable contaminant. 3224m – 3235m MDBRT Calcareous, very fine to fine grained, poorly sorted and well cemented SANDSTONE overlying highly DOLOMITIC LIMESTONE with good traces of CALCAREOUS CLAYSTONE. 25-100% CALCAREOUS SANDSTONE: Light brown, buff to beige, translucent, very firm, friable, quartzose aggregate, very fine to fine, trace medium, angular to subangular, elongate to rarely subspherical, very poorly sorted, strong calcareous and dolomitic cement, grain and cement supported, rare disseminated micropyrite, trace micromicaceous, trace discrete glauconite nodules, rarely grading to arenaceous siltstone, very poor visible porosity, no stain, no shows. 0-30% CALCAREOUS SANDY SILTSTONE: Brown to dark brown, very firm to hard, blocky, earthy, homogenous, strong calcareous cement - dolomitic in parts, rare argillaceous matrix, common very fine sand, micromicaceous in parts. 0-70% DOLOMITIC LIMESTONE: Grainstone to crystalline, translucent very light brown cream, rare off white, developing pale orange hue in basal 1m, hard, blocky to slightly brittle, angular break, dull to glassy, homogenous, trace discrete glauconite fragments, reworked & recrystallised in parts with hydrated soft, amorphous cryptocrystalline mud matrix, trace undifferentiated forams, very poor visible porosity, no shows. Trace-15% CALCAREOUS CLAYSTONE: Light grey, soft, amorphous, plastic, very calcareous, dull, homogenous, hygroturgid, common silty quartz

GAS Interval (m) Fro m 2993

Total Gas

To

Av (%)

3071

Trace

Maximum 3031 3071

3097

0.006 0.05

Maximum 3078 3097

3167

0.103 0.075

Maximum 3159 3167

3212

0.110 0.115

Maximum 3172 3212

3224

0.153 0.104

Maximum 3223 3224

3235

Maximum 3231

Max

0.132 0.12 0.23

Chromatograph (ppm) C1 (AV)

C2 (AV)

C3 (AV)

iC4 (AV)

nC4 (AV)

C5 (AV)

22

7

3

Trace

--

--

45

6

3

3

--

--

117

15

5

6

Trace

--

233

31

10

7

--

4

30

3

1

2

--

Trace

121

6

--

Trace

--

--

166

7

2

2

Trace

--

368

14

Trace

--

--

--

36

5

Trace

--

--

--

89

9

3

3

--

--

100

6

1

--

--

--

170

12

3

--

--

--

Please refer to the lithology descriptions for SHOW INFORMATION.

CORING None

WIRELINE LOGGING Please refer to ABCDEF-1_Run3_logReport.doc for full details on the wireline logging operations.

Geologists D. Kitson / Carlos Alberto/ B. Moore

WEEKLY SERVICE COMPANY REVIEW 06:00hrs, Monday 7th March 2009

Wellsite Geologists: Mud logging: MWD Wireline Well:

D. Kitson / Carlos Alberto SA Logging Inc. None Schlumberger Country:

ABCDEF

Colombia

Datalog EQUIPMENT

RIGGED UP

COMMENT

Gas Chromatograph

Yes

C1 – C5 in a 30 second cycle. Calibrated 27/02.

Total Gas

Yes

Catalytic combustion <5%, >5% TCD. Calibrated

CO2 Detector

Yes

27/02.

Sample Pump

Yes

Integral to the Total Gas

Gas Wizard

Yes

Operational below 1600m, on 8th Feb. Factory calibration and checked 27/02.

H2S Detector

Yes

1 sensor in ditch line only. On daily basis.

pH and pS Detector

Yes

Factory calibrated

Depth System

Yes

Crown block encoder and compensator pulleys

Pit level sensors

Yes

6 pits plus Trip tank (ultrasonic sensors). Calibrated 27/02.

Pump stroke counters

Yes

Proximity switches outside pump body – not ideal

Mud temp sensors

Yes

In / Out. Daily check.

Mud Density sensors

Yes

In / Out. Daily check.

Mud flow out

Yes

Flow show sensor (paddle)

RPM sensor

Yes

Direct from rig TDS

Rotary torque sensor

Yes

On TDS supply

Hook-load sensor

Yes

OK – Potentiometer clamped onto deadline

Standpipe pressure

Yes

OK 0 – 5,000-psi

Casing pressure

Yes

0 – 10,000 psi, from 8th Feb

Gas Trap

Yes

One regular gas trap with a spare agitator

Part of the Total Gas module

Unit pressurisation

Yes

OK, air intake on top of unit, recommend a longer duct run. 60 seconds depressurisation warning time, 25 minutes purge.

Microscope & light

Yes

Zoom and Halogen

Geologist’s Monitor

Yes

PC on SA Logging LAN

Yes


Yes


Drill Floor Monitor

Yes

Explosion proof housing

Flowback Monitoring software

Yes

Based on pit level sensor input, rather than return flow

Company Man’s Monitor Toolpusher’s Monitor

Mudlogging comments: No equipment problems reported. The crew are performing well and complying with all requests quickly and efficiently. Data delivery and self-QC of data has been most satisfactory. Morale remains good despite long and tiring rotations.

Correspondance on the correlation between Total Gas Detector and Gas Wizard data has been noted. This is ongoing, illustrated by the 17.8% / 1.3% GW / TGD ratio observed from an intermediary logging wiper trip. The total gas detector position is poor, located in a wide area gumbo-box allowing excessive natural degassing prior to extraction and measurement. The wizard extracts gas from an enclosed conventional flowline.

The logging cabin door needs urgent attention (highlighted by David earlier). However the cabin is being removed from the rig, thus enabling repairs to be made.

Current personnel on-board: Data Engineers : Gabriel Mpensa (replaced Christian Smith 03/03/05) Tiberi Trovia Mud Loggers : Richard Jones Valentin Viera (replaced Joe Bloggs 03/03/05) Datalogs’ attempt to minimise personnel utilisation on the project to 3 engineers and 3 mud-loggers has resulted in excessive rotations being worked by Gabriel and Joe in particular (the latter’s crew-change delayed 2 weeks due to the non-appearance of his relief). Whilst appreciating the difficulty of maintaining sufficient crew numbers during busy periods, this is nevertheless poor planning by SA Logging’s management.

Wireline Logging Comments Five runs were successfully completed (see ABCDEF-1_Run3_logReport.pdf ) with zero recorded downtime. Crew members performed their duties efficiently and safely with only minor QC issues resulting from the program. All are recommended. Personnel Engineer on-board during Log suite 3: Engineers: Juan Antonio/Antonio-Twoo Operators : Roger Federer/Andy Murray Ivan Camacho. VSP Operator : Alan Stubbs MDT Operator : Jason Lee Data Transmission: www.securedata.com 26th Feb 27th Feb 28th Feb 1st Mar 2nd Mar 3rd Mar 4th Mar DATE: Geo. Morning Yes Yes Yes Yes Yes Yes Yes report Geological Field Yes Yes Yes Yes Yes No No Log Formation Yes Yes Yes Yes Yes No No Evaluation Log Surface ASCII data Yes Yes Yes Yes Yes No No (LAS) Pressure No No No No No No No Evaluation log Drilling Data log No No No No No No No Hydocarbon No No No No No No No Evaluation Log Received at the rig: Mud logging reports

Yes

Yes

Yes

Yes

Yes

Yes

Yes

Data transmission Status • Satellite system has been reliable. • Full functionality with POP3 server bgspain.petrolink.net since 2nd Feb 2009. • No direct external line to Geologist. There are two lines present in the Geology / Mud engineer’s office (+55 977 743325/6 ex 216/9), which are extensions from the office exchange in San Siro. The only direct dial line to the rig is hooked up to a fax in the Company Man’s office (+55 977 744523).


Example Wellsite Geologist’s End-of-Well Report

Stag Geological Services Ltd. Reading UK

STAG NORTH SEA (UK) Co. Well: 15/19-6a Calleva Field

Wellsite Geological Report Horizontal Production Well

Stag Geological Services Ltd. 3 Fortuna Court Calleva Park Aldermaston Reading. RG7 8UB UK Tel: (0118) 982 0151 Fax: (0118) 982 0152

July 2001 WELLSITE GEOLOGISTS Cliff Becker Ralph Spooner

OPERATIONS GEOLOGIST David Martin

CONTENTS

Page No. 1.

INTRODUCTION ................................................................................................................. 2

2.

WELL DATA SUMMARY ..................................................................................................... 3

3.

FORMATION TOPS ............................................................................................................ 7

4.

LITHOSTRATIGRAPHY ...................................................................................................... 8

5.

WELL SURVEY DATA......................................................................................................... 14

1

1. Introduction Stag well 15/19-6a was drilled as a horizontal oil producer from slot #4. The well was drilled to access reserves from the furthest South Eastern part of Area A within the Headley Sandstone. Geological supervision commenced from 4180ft MDBRT (-2564ft TVDSS).

The 12 1/4” section was kicked-off at 1778ft MDBRT (-1588ft TVDSS) & drilled to 9017ft then a northseeking gyro was run to confirm and verify the MWD surveys. The well drilled into the Headley Sandstone reservoir to a section TD of 9795ft MDBRT (-2905ft TVDSS). This was designed in order to prevent having shale exposed in the “ratty” section of the top Headley Sandstone in the completed reservoir section and thus aid a successful gravel pack.

The 8 1/2” section was drilled horizontally from 9795ft to 10884ft. This wellpath drilled a course with considerable build and turned right to some 100ft right of the planned azimuth by a depth of 10884ft MD. This resulted in an equivalent “moving up” sequence within the Headley Sandstone, into a more interbedded or shaly sand and siltstone sequence. The well was therefore sidetracked from 10500ft in the form of Hz. This wellpath was drilled from 10500ft to 12316ft dropping TVD to find good reservoir sand. It drilled predominantly through sandy siltstone, therefore the well was sidetracked from 11110ft as Hy (to a depth of 11675 ft). This well was also sidetracked from 11270ft as Hx, essentially due to the perceived TVD elevation being too high in the structure, an inability to turn the wellbore left and move down structure, and encountering the Mid Headley Shale in the roof of LCS. This final wellpath was drilled from 11270 ft to 12681 ft, the well being swung back “leftwards” to the optimum track through the Headley Sandstone structure, and maintaining a TVDSS of around –2931 ft. Again more silty sandstones and siltstones were encountered than anticipated, the well being terminated at 12618 ft (-2932 ft TVDSS), having produced a net sand length of 1645 ft. Having cleaned up the well with a short wiper trip to the shoe an MDT and calliper log was run on drill pipe.

2

2. WELL DATA SUMMARY Well: Well Class: Well Type:

15/19-6a, Hz, Hy and Hx Development Horizontal Oil Producer

Operator: Partners:

Stag North Sea (UK) Co NESPC, 15%

Location: Area: Licence: Field:

North Sea, Offshore UK Block # 15/19 P 234 Headley

Slot: Surface:

#4 Latitude: 57° 19’ 29.786” N Longitude: 02° 48’ 7.655” E UTM: Zone 31 (CM 3° W) E: 582168.231m N: 6463887.807m

Primary Target:

Headley Sandstone

Rig: Rig Contractor: Type:

Sensco WPP “A” Sensco Platform

RT - MSL: RT - SEABED: Water depth: H Spud date: Hz Spud date: Hy Spud date Hx Spud date

155ft. 500ft. 345ft. 13th March 2001

02:30hrs

18th April 2001

08:30hrs

21st April 2001

02:30hrs

22nd May 2001

11:00hrs

3

TD Reached: Total depth:

27th May 2001 Drilled:

11:00hrs.

12681ft MD (-2932ft TVDSS)

HOLE SIZE & CASING DATA: Hole Size Depth Casing Point 26” 20” 12 1/4” H 8 ½” Hz 8 ½” Hy 8 ½” Hx 8 ½”

500 - 677ft 677 - 1800ft 1800 - 9795ft

677ft 1778ft 9747ft

9795 - 10882ft

-

Casing Diam

ppf/wall/grade

26” 16” 10.3/4 x 9.5/8”

270ppf/1.0/X52 75ppf/0.395/K55 BTC 55ppf/0.49/L80 NVAM 40ppf/0.39/L80 NVAM

10500 - 12316 11110 - 11675 11270 - 12681

MUD SYSTEM: Mud Weight (ppg) Viscosity(YP) Interval (1) Spud Mud; sea water with Gel/Guar Gum Sweeps (Baroid) 500 - 1800ft 8.6 (10.3) --(2) KCl Polymer/Glycol Barite Weighted (Baroid) 1800 - 9795ft 9.6 (11.9) 14 (27) (3) Baradrill calcium carbonate weighted (Baroid) 9795 – 12681ft 9.2 (9.6) 45(60)

Filtrate --3.0 (6.0) 2.0(2.8)

SURVEY LOGS: A Gyrodata pump down gyro was run in inside 16” casing and 12 ¼” open hole section and gave the TD as 13ft TVD low to MWD and 50ft to the right of the MWD. Run No.

Tools run

Interval (ft)

Date

1

Cased Hole Gyro

500-1778

02/03/01

1

Open Hole Gyro

1778-8750

02/03/01

4

MEASUREMENT WHILE DRILLING LOGS: LWD: ANADRILL Run no. 20” Hole 1 12-1/4” 2 3 4 8-1/2” 5 6 7

Tools Run

Interval (ft) Logged

Date From - to

MWD/GR

1135 – 1735

14/03 – 15/03/01

MWD/GR MWD/GR RAB/ADN6/MWD/GR

1735 – 5537 5537 – 6646 6646 – 9758

17/03 – 21/03/01 22/03 – 25/03/01 28/03 – 03/04/01

RAB/GST/ADN6/MWD RAB/ADN6/MWD RAB/ADN6/MWD

9758 – 10462 10462 – 11711 11711 – 12661

15/04/01 – 16/04/01 17/04/01 – 25/04/01 25/04/01 – 27/04/01

RUN REPORT - MWD Run 6 ran out of memory in the RAB tool at 11520ft so only telemetry data was recorded at surface essentially due to the need to sidetrack in open hole during the run. Run 7 lost communication at 11770ft with the near bit inclination being transmitted from the “short hop” electronics of the Powerdrive in addition to this an apparent failure in communication of the ADN tool, turned out to be a complete tool failure and hence no memory data or telemetry data was acquired from 11951ft to TD of the last side track Hx.

CUTTINGS SAMPLES: Drill cuttings samples were collected for 15/19-6a from below the 16” casing shoe at 1778ft to 10880ft in the 8½” hole section. Thereafter they were collected in the 8½” section for wellpath Hz from 10500ft to 12316ft, from 11110ft to 11675ft for wellpath Hy and 11270ft to 12681ft for wellpath Hx. Hole Size (in) 12 ¼” & 8 ½”

Hz Hole Size (in) 8 ½”

Hy Hole Size (in) 8 ½”

Hx Hole Size (in) 8 ½”

Depth Interval (ft) 1778-10880




Type 1 x 100g Washed & Dried 2 x 500g Unwashed & Wet

Sample Interval 20ft





Type 1 x 100g


5

20ft

20ft

20ft

Washed & Dried 2 x 500g Unwashed & Wet

20ft

SAMPLE DESTINATIONS: Hays Information Management Wellheads Crescent Dyce Industrial Park Aberdeen AB2 0HG (Attn: Alan Scott)

1 set unwashed & wet Set A

RPS Palaeo Unit 2 Robert Leonard Centre Kirkhill Industrial Estate Dyce AB2 0GL (Attn: P. Mears)

1 set unwashed & wet Set B

The Curator BGS/DTI Core Store 276 Gilmerton Road Edinburgh EH17 7QS.

1 set washed & dried

Set C

HOT SHOT BIOSTRAT: Hotshot samples that were sent off for analysis were taken 10400ft from the H wellbore, 10860ft, 11060ft, 11760ft, 12000ft, 12180ft from the Hz wellbore. The full biostratigraphy report performed by RPS Palaeo will be included later.

BIT DATA: Bit No.

Type

Size

Depth in

Depth out

Ftg

1RR

Smith DSJC

23”

667

709

42

2

HTC GTX-CG1

20”

709

1200

491

2RR

HTC GTX-CG1

20”

1200

1800

600

3

Geodiamond MRS89PX

12-¼"

1800

5589

3789

4

Smith M50SPX

12-¼"

5589

6713

1124

5

Smith M50SPX

12-¼"

6713

9795

3082

6

Hycalog DS71 HGJ

8-½”

9795

10462

667

7

Hycalog DS130 DF

H

8-½”

10462

10884

422

Hycalog DS130 DF

Hz

8-½”

10500

12316

1816

Hycalog DS130 DF

Hy

8-½”

11110

11675

565

Hycalog DS130 DF

Hx

8-½”

11270

11731

461

Hycalog DS130 DF

Hx

8-½”

11731

12681

950

7RR1

6

3. FORMATION TOPS DEPTH (ft) MD TVDSS

UTM 3deg W (m) Y X

Mean Sea Level

155

0

Sea Bed

500

-345

Top F1 Formation

2570

-2212

572354.69

6463631.35

Top RC Marker

2618

-2241

572364.46

6463625.11

Base RC Marker

2816

-2347

572407.57

6463598.01

Top LF

3503

-2518

572578.27

6463492.14

Top H

5521

-2657

573093.72

6463159.92

Base S-R

9070

-2880

573983.82

6462551.44

Top Upper Headley Sand

9107

-2882

573993.22

6462545.10

Top Mid Headley Shale

9260

-2889

574031.55

6462518.64

Top Headley Sandstone

9612

-2897

574119.45

6462457.24

Top Intra shale#1

10278

-2902

574288.61

6462339.88

Base Intra shale#1

10439

-2903

574316.10

6462320.17

Base Mid Headley Shale

11519

-2917

574609.7

6462148.17

TD (in Hx)

12681

-2932

574923.31

6461983.97

15/19-6aWell UPPER CRETACEOUS

LOWER CRETACEOUS

15/19-6a

7

4. LITHOSTRATIGRAPHY All depths are drilled depths, unless otherwise stated, referred to the rotary table. A top drive system was used.

CRETACEOUS Chalk Group LF Formation:

3503ft to 5521ft MDBRT (-2518ft to -2657ft TVDSS) This section consists of chalk limestone, mudstone, and wackestone, more homogeneous, and less argillaceous than the UF. The limestone is off white to white, occasionally light to medium grey, rarely red pink, rarely very light green, soft to firm, locally hard, blocky to subblocky, crumbly, generally cryptocrystalline, also microcrystalline with no visible porosity, with rare calcite crystals and quartz grains. Minor limestone is variably argillaceous, as inter-laminations and grades into marl, and there are rare traces of glauconite and pyrite. GAS VALUES: Total Gas (%)

C1(ppm)

C2(ppm)

C3(ppm)

IC4(ppm) NC4(ppm)

Maximum Gas

1.70

11084

0

0

0

0

Background Gas

0.20

2500

0

0

0

0

H Formation:

5521ft to 9070ft MDBRT (-2657ft to -2880ft TVDSS) Limestone in this section is commonly argillaceous and marly, is much more variable than the F Formation, and consequently has more gamma ray character to enable correlation. The limestone is dominantly off white to cream, locally light brown-yellow to light blue-green, locally grey, generally soft to firm, locally hard, crumbly in places, subblocky to subangular, mudstone to wackestone, microcrystalline to cryptocrystalline, with local argillaceous laminations and trace glauconite. The marl is soft to firm, slightly glauconitic & in places inter-laminated with the limestone. The marl is more abundant & argillaceous with depth. Thin variously calcareous claystone stringers are present, predominantly towards the top of the section and are generally grey to dark grey-brown and locally blue-green and red-brown whilst the darker varieties are moderately silty, increasingly so with depth. GAS VALUES: Total Gas (%)

C1(ppm)

C2(ppm)

C3(ppm)

IC4(ppm) NC4(ppm)

Maximum Gas

0.74

7425

204

0

0

0

Background Gas

0.13

2170

0

0

0

0

8

LOWER CRETACEOUS CK Group Base Chalk S_R Formation:

9070ft to 9107ft MDBRT (-2880ft to -2882ft TVDSS) This interval consists of a varicoloured claystone. The samples were heavily contaminated with chalk limestone from the above formation. The claystone is green, light green, very pale green, yellow-brown, brick red, purple, soft to firm, amorphous to subblocky, slightly silty, and none calcareous.

GAS VALUES: Total Gas (%)

C1(ppm)

C2(ppm)

C3(ppm)

IC4(ppm) NC4(ppm)

Maximum Gas

0.156

1194

0

0

0

0

Background Gas

0.112

800

0

0

0

0

Valhall Formation Upper Headley Sand:

9107ft to 9260ft MDBRT (-2882ft to –2889ft TVDSS) Though not anticipated, a thin section of the Upper Headley Sand was encountered on the well track. It comprises clean unconsolidated friable sand. The sand is colourless quartz, locally very pale brown-pink, is transparent to translucent, fine to medium grained, though locally coarse or very coarsely grained, is subangular to rounded, though generally subrounded to rounded and has moderate sphericity. It has moderate to poor sorting, has weak calcareous cement, and shows very good visual porosity. A light brown oil stain is observable on most grains, these showing a pale yellow fluorescence and produce a slow diffuse blue-white cut. GAS VALUES: Total Gas (%)

C1(ppm)

C2(ppm)

C3(ppm)

IC4(ppm) NC4(ppm)

Maximum Gas

7.383

21966

2823

572

101

12

Background Gas

0.48

4922

65

0

0

0

9

Mid Headley Shale:

9260ft to 9612 ft MDBRT (-2889ft to –2897ft TVDSS)

This section is one of claystone with minor sandstone between 9325 ft and 9340 ft MD, which did show a poor hydrocarbon show and dull yellow fluorescence. The claystone is grey to dark grey, locally grey-green to dark grey-green, and is very silty, locally grading to fine sand. It is locally slightly calcareous, locally micaceous, and contains carbonaceous fragments. The sand is colourless quartz, locally very pale brown-pink. It is transparent to translucent, generally fine to medium grained, though locally coarse or very coarse. In shape the grains are subangular to rounded, though generally subrounded to rounded, exhibit moderate sphericity, and are moderately to poorly sorted. Sandstone occasionally appears in cuttings, with weak calcareous cement and exhibiting good visual porosity. No oil stain was noted. 40% of cuttings have pinpoint dull to moderate yellow fluorescence, and there is no cut. GAS VALUES: Total Gas (%)

C1(ppm)

C2(ppm)

C3(ppm)

IC4(ppm) NC4(ppm)

Maximum Gas

1.606

11521

671

65

6

0

Background Gas

0.348

4736

65

0

0

0

Headley Sandstone:

9612ft to 10884ft MDBRT (-2897ft to –2888ft TVDSS) This section comprises generally clean, unconsolidated, sand however towards the top of LHS2 there is a “shaly” interbedded sequence in which siltier sand grades to a silty claystone. The sand is primarily quartz, which is clear or very pale brown, locally very pale grey and pale pink. Very rarely slightly feldspathic seen as pink-orange to light grey grains. It is transparent to translucent, locally with polished and frosted grains, is generally fine to medium grained, though is rarely coarse. The grains are subangular to subrounded, generally subrounded to rounded, exhibit good sphericity, and are moderate to well sorted. Sandstone occasionally appears with weak calcareous cement, shows good visual porosity, excellent inferred porosity, and has traces of glauconite and pyrite. Moderate light brown oil stain, good to fair pale yellow to bright yellow fluorescence, slow to very slow diffuse cut of blue-white to yellow-white. GAS VALUES: Total Gas (%)

C1(ppm)

C2(ppm)

C3(ppm)

Maximum Gas

9.008

22227

2291

570

13

6

Background Gas

0.537

8079

152

4

0

0

10

IC4(ppm) NC4(ppm)

Headley Sandstone: Intra Shale#1

10278ft to 10439ft MDBRT (-2902ft to –2905ft TVDSS)

This section comprised soft grey silty claystone. The claystone is generally grey-brown locally dark grey-brown, generally soft, rarely firm, predominantly exhibiting a subblocky break. Generally silty throughout but locally increasingly silty and locally grades to siltstone. Varying from slightly to moderately calcareous, trace minerals included varying amounts of glauconite and mica. GAS VALUES: Total Gas (%)

C1(ppm)

C2(ppm)

C3(ppm)

IC4(ppm) NC4(ppm)

Maximum Gas

0.435

6266

64

0

0

0

Background Gas

0.25

2800

15

0

0

0

SIDETRACK Hz Headley Sandstone:

10500ft to 12316ft MDBRT (-2903ft to –2920ft TVDSS) This section comprises generally clean unconsolidated sand however towards the top of LHS2 there is a “shaly” interbedded sequence in which more silty sands grade to a silty claystone. The sand is primarily quartz, which is clear or very pale brown, locally very pale grey and pale pink. Very rarely slightly feldspathic seen as pink-orange to light grey grains. The sand grains are transparent to translucent, locally with polished and frosted grains, are generally fine to medium sized, though are locally coarse to very coarse with rare granules. The grains are subangular to subrounded, generally subrounded to rounded, exhibit good sphericity, and are moderate to well sorted. It occasionally occurs as sandstone with weak calcareous cement, shows good visual porosity and excellent inferred porosity, and has traces of glauconite and pyrite. Having a moderate light brown oil stain, good to fair pale yellow to bright yellow fluorescence, slow to very slow diffuse cut of blue white to yellow white. GAS VALUES: Total Gas (%)

C1(ppm)

C2(ppm)

C3(ppm)

IC4(ppm) NC4(ppm)

Maximum Gas

5.97

19946

2034

325

0

0

Background Gas

1.53

11323

536

23

0

0

11

SIDETRACK Hy Headley Sandstone:

11110ft to 11519ft MDBRT (-2906ft to –2917ft TVDSS) This section comprises interbedded clean unconsolidated sand with silty claystone. Good shale was observed at 11519ft to 11580ft which having had a provisional micropalaeontological analysis of shale’s in the previous Hz well bore placed those as basal Mid Headley Shale or Topmost Headley Sandstone. The sand is primarily quartz, which is clear or very pale brown, locally very pale grey and pale pink. Very rarely slightly feldspathic seen as pink-orange to light grey grains. The sand grains are transparent to translucent, locally with polished and frosted grains, is generally fine to medium sized, though it is locally coarse to very coarse with rare granules. The grains are subangular to subrounded, generally subrounded to rounded, exhibit good sphericity, and are moderate to well sorted. It occasionally occurs as sandstone with weak calcareous cement, shows good visual porosity and excellent inferred porosity, and has traces of glauconite and pyrite. Having a moderate light brown oil stain, good to fair pale yellow to bright yellow fluorescence, slow to very slow diffuse cut of blue-white to yellow-white.

GAS VALUES: Total Gas (%)

C1(ppm)

C2(ppm)

C3(ppm)

IC4(ppm) NC4(ppm)

Maximum Gas

6.66

21762

2338

421

10

12

Background Gas

2.25

7875

402

45

0

0

Mid Headley Shale:

11519ft to 11675ft MDBRT (-2917ft to –2918ft TVDSS) This section is predominantly claystone that grades to siltstone at the very base. It was encountered from below as the well bore moved up section into the Mid Headley Shale. The claystone is grey to dark grey, predominantly soft with an amorphous break. Much of the claystone is sandy/silty and micaceous in parts, and slightly calcareous. Locally the claystone graded to siltstone. The siltstone is grey to dark grey and locally grey green, generally soft with an amorphous break. In parts it is very sandy and very micaceous, non- to slightly calcareous. GAS VALUES: Total Gas (%)

C1(ppm)

C2(ppm)

C3(ppm)

Maximum Gas

1.50

9311

357

57

0

0

Background Gas

0.39

3335

31

0

0

0

12

IC4(ppm) NC4(ppm)

SIDETRACK Hx Headley Sandstone:

11270ft to 12681ft MDBRT (-2914ft to –2932ft TVDSS) This section comprises a predominantly sand rich sequence with local interbeds of siltstone, which are interpreted as the “shaly” interbedded top-most Headley Sandstone. However below a 160ft thick siltstone drilled between 11890ft and 12050 ft, the character of the LHS changes from predominantly sand rich to a siltstone rich sequence with small interbeds or stringers of sand. The sand is primarily quartz, which is clear or very pale brown, locally very pale grey and pale pink. It is very rarely slightly feldspathic, seen as pink-orange to light grey grains in cuttings samples. The sand grains are transparent to translucent, locally with polished and frosted grains, is generally fine to medium sized, though it is locally coarse to very coarse with rare granules. The grains are subangular to subrounded, rarely subplatey, exhibit good sphericity, are moderate to well sorted. Sandstone occasionally occurs as with weak calcareous cement, shows good visual porosity and excellent inferred porosity, and has traces of glauconite and pyrite. There is a trace to moderate to light brown oil stain, pinpoint to uniform, good to fair, pale yellow to bright yellow fluorescence, very slow to moderate diffuse cut of blue-white to yellow-white. The siltstone is grey to dark grey and locally grey-green, generally soft with an amorphous break. In parts it is very sandy and very micaceous, none to slightly calcareous becoming moderately calcareous below 12000ft. GAS VALUES: Total Gas (%)

C1(ppm)

C2(ppm)

C3(ppm)

IC4(ppm) NC4(ppm)

Maximum Gas

4.92

19364

2206

360

42

780

Background Gas

0.70

5131

155

0

0

0

13

WELL SURVEY DATA Stn TIP MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD

Depth 1729 1990 2084 2180 2268 2367 2463 2559 2653 2748 2842 2937 3031 3126 3220 3315 3408 3503 3599 3687 3779 3882 3977 4074 4167 4264 4357 4451 4546 4642 4733 4826 4924 5017 5113 5207 5302 5396 5489 5539 5630 5723 5810 5899 5989

INC 24.74 31.18 34.14 37.46 39.99 43.09 46.85 50.95 54.92 59.03 62.84 66.70 70.54 74.55 78.43 82.34 85.11 85.62 86.08 86.37 86.51 86.48 86.23 85.85 85.62 85.59 85.71 85.68 85.82 86.25 86.37 86.66 86.74 86.54 86.34 86.05 85.68 85.54 85.05 84.53 86.20 86.54 86.54 86.63 86.88

AZI 121.64 124.54 123.46 123.90 123.07 122.61 122.69 122.50 122.68 121.75 122.03 121.84 122.07 121.62 121.88 121.92 121.54 121.47 121.29 121.22 120.87 120.62 120.90 121.85 121.64 122.32 122.41 123.28 123.42 123.97 124.29 124.52 124.64 124.66 124.04 123.94 123.46 123.25 123.02 123.54 124.59 124.57 124.61 124.69 124.87

TVD 1698.33 1929.57 2008.70 2086.55 2155.20 2229.29 2297.20 2360.29 2416.94 2468.70 2514.36 2554.84 2589.11 2617.60 2639.55 2655.42 2665.58 2673.26 2680.20 2686.00 2691.71 2698.01 2704.05 2710.75 2717.66 2725.10 2732.15 2739.21 2746.25 2752.89 2758.74 2764.39 2770.04 2775.49 2781.45 2787.69 2794.54 2801.73 2809.36 2813.90 2821.25 2827.14 2832.39 2837.69 2842.79

Vert Sect 222.68 343.36 394.07 450.21 505.25 570.90 638.73 711.06 786.05 865.67 947.81 1033.72 1121.22 1211.81 1303.18 1396.81 1489.23 1583.89 1679.60 1767.38 1859.15 1961.89 2056.63 2153.36 2246.09 2342.79 2435.52 2529.25 2623.99 2719.75 2810.54 2903.33 3001.13 3093.92 3189.71 3283.48 3378.22 3471.94 3564.63 3614.42 3705.10 3797.87 3884.68 3973.48 4063.28

14

Northing 6463714.01 6463694.00 6463685.36 6463675.87 6463666.62 6463655.77 6463644.62 6463632.75 6463620.44 6463607.51 6463594.29 6463580.44 6463566.33 6463551.76 6463537.11 6463522.03 6463507.22 6463492.14 6463476.95 6463463.07 6463448.64 6463432.63 6463417.85 6463402.50 6463387.63 6463372.03 6463356.90 6463341.41 6463325.54 6463309.35 6463293.83 6463277.85 6463260.93 6463244.84 6463228.37 6463212.39 6463196.38 6463180.67 6463165.24 6463156.91 6463141.43 6463125.38 6463110.36 6463094.97 6463079.35

Easting 572227.82 572258.67 572271.48 572285.72 572299.71 572316.52 572333.92 572352.49 572371.74 572392.27 572413.52 572435.74 572458.36 572481.82 572505.49 572529.72 572553.67 572578.27 572603.18 572626.05 572650.02 572676.94 572701.77 572726.94 572750.97 572775.97 572799.83 572823.83 572847.94 572872.22 572895.12 572918.46 572943.00 572966.28 572990.38 573014.07 573038.09 573061.95 573085.59 573098.28 573121.17 573144.46 573166.24 573188.51 573211.00

DLS 2.85 3.21 3.47 2.93 3.15 3.92 4.27 4.23 4.40 4.06 4.07 4.09 4.25 4.14 4.12 3.01 0.54 0.51 0.34 0.41 0.24 0.39 1.05 0.33 0.70 0.16 0.92 0.21 0.73 0.37 0.40 0.15 0.22 0.68 0.33 0.64

0.27 0.58 1.47 2.17 0.37 0.05 0.14 0.34

Stn MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD MWD

Depth 6080 6173 6263 6356 6449 6540 6631 6782 6874 6964 7056 7147 7237 7327 7417 7506 7598 7693 7784 7870 7966 8057 8145 8234 8325 8415 8510 8606 8692 8783 8874 8962 9054 9147 9238 9327 9415 9508 9598 9692 9717 9740 9825 9918 10010 10108 10199

INC 87.17 87.40 87.57 87.80 87.14 87.34 87.17 86.22 86.16 85.93 85.93 86.04 85.93 85.62 85.24 85.21 85.36 85.70 87.99 88.99 88.42 87.85 87.48 87.16 86.79 86.39 86.11 86.22 86.31 86.02 86.22 86.56 86.73 87.73 87.45 88.39 88.96 88.99 88.68 87.28 87.19 87.68 90.00 90.83 92.29 90.63 87.60

AZI 124.67 125.04 124.57 125.03 124.01 124.45 124.04 122.73 122.49 122.74 122.09 121.71 121.52 121.47 121.99 122.36 122.63 122.27 122.20 121.43 121.65 122.61 124.09 124.66 124.54 123.93 123.86 123.57 123.48 123.61 123.95 123.85 124.12 124.62 124.66 124.67 125.00 125.20 124.93 124.58 125.04 125.14 124.53 124.39 125.53 124.15 124.53

TVD 2847.51 2851.92 2855.87 2859.62 2863.73 2868.11 2872.47 2881.17 2887.29 2893.49 2900.02 2906.40 2912.70 2919.33 2926.50 2933.91 2941.47 2948.87 2953.88 2956.15 2958.32 2961.28 2964.86 2969.03 2973.83 2979.19 2985.39 2991.82 2997.42 3003.50 3009.66 3015.20 3034.30 3038.80 3042.62 3045.85 3047.89 3049.55 3051.38 3054.70 3055.90 3057.61 3059.33 3058.66 3056.15 3053.66 3055.06

Vert Sect 4154.11 4246.95 4336.81 4429.68 4522.55 4613.42 4704.29 4855.03 4946.82 5036.61 5128.37 5219.14 5308.89 5398.62 5488.32 5577.00 5668.69 5763.40 5854.25 5940.20 6036.15 6127.09 6215.01 6303.89 6394.72 6484.52 6579.30 6675.08 6760.89 6851.69 6942.47 7030.28 7118.21 7211.07 7301.95 7390.84 7478.77 7571.68 7661.60 7755.49 7780.45 7803.27 7888.19 7981.15 8073.05 8170.95 8261.89

15

Northing 6463063.56 6463047.38 6463031.75 6463015.59 6462999.54 6462983.97 6462968.38 6462943.11 6462928.03 6462913.29 6462898.30 6462883.68 6462869.34 6462855.05 6462840.68 6462826.29 6462811.28 6462795.80 6462781.03 6462767.22 6462751.92 6462737.18 6462722.46 6462707.16 6462691.44 6462676.04 6462659.93 6462643.73 6462629.29 6462614.00 6462598.62 6462583.70 6462554.18 6462538.20 6462522.45 6462507.04 6462491.73 6462475.44 6462459.68 6462443.37 6462439.02 6462435.00 6462420.21 6462404.18 6462388.12 6462371.07 6462355.43

Easting 573233.74 573256.97 573279.46 573302.71 573326.04 573348.94 573371.83 573410.18 573433.74 573456.79 573480.39 573503.87 573527.17 573550.49 573573.74 573596.61 573620.17 573644.53 573667.94 573690.20 573715.13 573738.59 573760.97 573783.33 573806.12 573828.75 573852.73 573877.01 573898.80 573921.86 573944.85 573967.07 573979.89 574003.25 574026.04 574048.33 574070.33 574093.51 574115.95 574139.47 574145.72 574151.44 574172.70 574196.06 574219.02 574243.52 574266.41

DLS 0.39 0.47 0.55 0.55 1.31 0.53 0.49 1.07 0.27 0.38 0.70 0.43 0.24 0.35 0.71 0.42 0.33 0.52 2.52 1.47 0.64 1.23 1.73 0.73 0.43 0.81 0.30 0.32 0.15 0.35 0.43 0.40 0.35 1.20 0.31 1.06 0.75 0.22 0.46 1.54 1.87 0.00 2.82 0.91 2.01 2.20 3.36

Stn Depth INC AZI MWD 10292 89.34 125.53 MWD 10384 89.91 125.74 MWD 10459 90.14 125.44 MWD 10547 91.89 122.35 MWD 10640 93.17 119.65 MWD 10726 92.34 117.17 * 10884 91.20 114.00 *Projection at TD of H original wellbore

TVD 3057.54 3058.15 3058.11 3056.55 3052.45 3048.31 3043.43

Vert Sect 8354.79 8446.67 8521.58 8609.54 8702.39 8788.03 8944.68

Northing 6462339.17 6462322.84 6462309.54 6462294.59 6462280.02 6462267.56 6462246.79

Easting 574289.61 574312.39 574330.97 574353.22 574377.48 574400.50 574443.90

DLS 2.16 0.66 0.50 4.03 3.21 3.04 2.13

SIDETRACK Hz Stn Depth INC AZI TVD Vert Sect MWD 10459 90.14 125.44 3058.11 8521.58 MWD 10551 89.37 123.15 3058.51 8613.54 MWD 10641 88.34 119.89 3060.31 8703.49 MWD 10730 88.23 118.17 3062.97 8792.25 MWD 10822 88.66 117.30 3065.47 8883.86 MWD 10913 91.26 116.68 3065.53 8974.38 MWD 11003 92.00 116.19 3062.97 9063.79 MWD 11081 90.66 115.82 3061.16 9141.22 MWD 11181 90.49 117.56 3060.16 9240.64 MWD 11277 94.58 121.03 3055.91 9336.34 MWD 11365 90.57 120.30 3051.96 9424.17 MWD 11456 91.31 122.09 3050.46 9515.12 MWD 10551 89.37 123.15 3058.51 8613.54 MWD 10641 88.34 119.89 3060.31 8703.49 MWD 10730 88.23 118.17 3062.97 8792.25 MWD 10822 88.66 117.30 3065.47 8883.86 MWD 10913 91.26 116.68 3065.53 8974.38 MWD 11081 90.66 115.82 3062.71 9141.26 MWD 11181 90.49 117.56 3061.71 9240.68 MWD 11277 94.58 121.03 3057.46 9336.38 MWD 11365 90.57 120.30 3051.96 9424.17 MWD 11456 91.31 122.09 3050.46 9515.12 MWD 11545 88.86 121.17 3050.33 9604.09 MWD 11637 89.03 120.20 3052.03 9696.01 MWD 11729 87.34 118.67 3054.94 9787.80 MWD 11805 87.91 117.02 3058.09 9863.45 MWD 11907 90.06 117.70 3059.90 9964.96 MWD 12000 89.69 119.42 3060.10 10057.71 MWD 12091 89.57 120.04 3060.69 10148.57 MWD 12182 86.57 117.99 3063.75 10239.31 * 12316 84.19 118.00 3074.54 10372.39 * Projected survey at TD of well track 13/22a-Hz.

Northing 6462309.54 6462293.75 6462279.42 6462266.26 6462253.22 6462240.64 6462228.44 6462218.02 6462204.34 6462190.04 6462176.39 6462162.03 6462293.75 6462279.42 6462266.26 6462253.22 6462240.64 6462218.00 6462204.32 6462190.03 6462176.39 6462162.03 6462147.81 6462133.50 6462119.74 6462108.93 6462094.65 6462081.10 6462067.35 6462053.91 6462034.81

Easting 574330.97 574354.13 574377.50 574401.20 574426.00 574450.70 574475.25 574496.60 574523.82 574549.30 574572.34 574596.05 574354.13 574377.50 574401.20 574426.00 574450.70 574496.61 574523.83 574549.30 574572.34 574596.05 574619.14 574643.24 574667.64 574668.10 574715.69 574740.58 574764.66 574788.89 574824.82

DLS 0.50 2.63 3.80 1.94 1.05 2.94 0.99 1.78 1.75 5.58 4.63 2.13 2.63 3.80 1.94 1.05 2.94 0.62 1.75 5.58 4.63 2.13 2.94 1.07 2.48 2.30 2.21 1.89 0.69 3.99 1.78

16

SIDETRACK Hy Stn Depth INC AZI TVD Vert Sect MWD 11186 86.71 116.19 3063.57 9245.44 MWD 11277 86.83 120.04 3068.70 9335.97 MWD 11368 89.30 125.45 3071.77 9426.88 MWD 11456 90.74 128.12 3071.74 9514.65 MWD 11545 90.26 127.07 3070.97 9603.34 * 11675 87.60 124.00 3073.39 9733.14 * Projected survey at TD of well track 15/19-6a.

Northing 6462204.00 6462190.96 6462175.97 6462159.92 6462143.38 6462120.36

Easting 574525.34 574549.76 574573.05 574594.53 574616.01 574648.23

DLS 3.78 4.23 6.53 3.45 1.30 3.12

SIDETRACK Hx Stn Depth INC AZI TVD Vert Sect 11278 86.40 119.52 3069.10 9336.91 MWD MWD 11366 85.25 120.60 3075.51 9424.58 MWD 11456 87.97 121.93 3080.83 9514.38 MWD 11546 89.31 119.85 3082.96 9604.30 MWD 11636 88.29 118.81 3084.85 9694.11 MWD 11694 86.71 118.97 3087.38 9751.96 MWD 11792 87.11 119.45 3092.66 9849.62 MWD 11884 88.11 119.34 3096.50 9941.37 MWD 11976 91.00 118.51 3097.21 10033.13 MWD 11976 91.00 118.51 3097.21 10033.13 MWD 12069 95.13 114.48 3092.24 10125.39 MWD 12158 94.17 115.78 3085.02 10213.28 MWD 12249 92.57 117.67 3079.67 10303.59 MWD 12340 90.31 118.00 3077.39 10394.20 MWD 12434 90.09 118.94 3077.06 10487.92 MWD 12522 87.60 119.71 3078.83 10575.73 MWD 12614 86.36 121.91 3083.68 10667.53 * 12681 87.40 122.50 3087.33 10734.43 * Projected survey at TD of well track 13/22a-Hx.

Northing 6462190.93 6462177.53 6462163.33 6462149.25 6462135.82 6462127.29 6462112.74 6462099.00 6462085.44 6462085.44 6462072.82 6462061.34 6462048.90 6462035.95 6462022.30 6462009.17 6461994.84 6461983.97

Easting 574550.08 574573.22 574596.62 574620.15 574644.05 574659.51 574685.53 574709.93 574734.46 574734.46 574759.78 574784.25 574808.97 574833.48 574858.65 574882.02 574906.07 574923.31

DLS 3.63 1.79 3.36 2.75 1.62 2.74 0.64 1.09 3.27 3.27 6.20 1.81 2.72 2.51 1.03 2.96 2.74 1.78

17

Smith Tool IADC 111 Type

DSJ Size

24"

(609.6mm)

10464;Drilling Drilling Applications Applications Designed for soft-formation, top-hole drilling in low-strength, unconsolidated clays, sands and silty marine sediments. Typically used as a spud bit.

Design Specifications 9744;Design Specifications Bearing Type Seal Type Journal Angle Offset Number of Rows Number of Teeth Bit Connection Type

Open Roller 32-1/2º 3/8" 11 144 7-5/8" Reg.

General Operating Parameters 9744;General Operating Parameters Weight-on-bit Lbs. daN Tonnes Rotary Speed

20,000 to 45,000 8,896 to 20,017 9 to 20 70 to 180 rpm

Features Benefits 3240|360|6144;Features||Benefits; Aggressive cutting structure

Maximizes ROP in medium-soft formations and maintains cutting structure integrity in formation changes.

Maximum offset

Allows drilling at high ROP in speed-responsive formations.

Non-sealed roller

Low-cost bearing capable of high speeds for short runs.

DbP970820140250 - Smith Tool Technical Services Rock Bit Database v 3. 1. 24

ER 906

12-1/4" M50

IADC Code: M433

Design Specifications Total Cutters:

70

Cutter Size:

13mm (1/2")

Face:

64

Gage:

6

Nozzles:

6 Series 60N

Junk Slot Area:

36.3 in. sq.

Gage Length:

3.0"

Gage Protection:

Options Available

Make-Up Length:

12.6"

Bit Connection:

6-5/8" API Regular

Fishing Neck:

Diameter 8.0" / Length 5.6”

Overall: 18.1"

Features Advanced Cutter Placement Force Balanced Unsymmetrical Blade Layout Spiraled Blades and Gage

Options Special options are available upon request.

Operating Parameters Rotary Speed:

Suitable for Rotary, PDM & Turbine

Weight-on-Bit:

6,000 - 50,000 LBS

Flow Rate:

500-800 GPM

Picture may one or more of the available options.

Hydraulic Horsepower: 1.0 - 6.0 HSI The M50 is a matrix body bit designed with stability enhancing features. Applications ranging from medium soft to medium hard formations. Good for transitional and directional drilling.

Geo-data.0365-01.0398 ©1998 Smith International. All rights reserved.

Reed-Hycalog Steerable Rotary Bits Brochure

Control and performance for steerable rotary drilling The Reed-Hycalog Steerable Rotary Bit (SRB) family provides PDC performance and roller cone control in steerable rotary drilling applications. The design is engineered to meet the unique requirements of rotary steerable systems based on thrust pads, today's market leading technology. Building on the success of the Hycalog DS130, the industry's first rotary steerable bit, the SRB series enhances tight radius drilling with aggressive, durable bits that yield high rates of penetration.

Product Features •

Low Aspect

Reed-Hycalog Steerable Rotary Bits Drill tight-radius wellbores with rotary steerable systems Tight radius wellbores The SRB family of PDC bits for steerable rotary drilling employs the Hycalog Low Aspect Ratio (LAR*) design for a very short overall length and a short, aggressive gauge to provide a distinct advantage in drilling tight radius wellbores. The 8 1/2 in. DS130, for example, has an overall length of only 6.8 inches. Because the bit is shorter, the distance between the displacement pads on the steering tool and the bit force on the rock is reduced. The distance between these points defines the hole's curvature. When this distance is as short as possible, control and dogleg potential are maximized. This tight radius capability is critical when using steerable rotary tools such as the Schlumberger PowerDrive* system, which "pushes" the bit laterally to deviate the wellbore.

Aggressive side cutting action During tight radius drilling, control and efficiency are reduced by the angle created between the bit axis and the borehole axis. Overcoming this angle requires a side force delivered by the steering tool and a bit that applies this force to cutters on the inside of the hole curvature. Hycalog Steerable Rotary Bits address this requirement with a very short, aggressive gauge which converts lateral steering force into positive lateral deviation. The result is a very capable bit for addressing difficult dogleg requirements. The short gauge focuses the energy that is transferred from the bit to the formation. This energy is applied to PDC cutters on the gauge. These uniquely placed cutters actively cut the formation to allow maximum lateral wellbore deviation. Cutter angle and orientation are

vibration to provide greater bit stability.

Aggressive PDC back rake SRB bits take advantage of the inherent capabilities of steerable rotary systems to provide a much more aggressive cutting structure. Because conventional steering systems using motors are required to slide and retain tool face orientation, reactive torque is a problem. The solution has been to compen-sate for this reactive torque by employing less aggressive bits. This was accomplished by increasing the back rake, or angle at which the PDC cutters meet the rock. This solution, although effective, caused penetration rates to be reduced. Steerable rotary systems do not have to address this problem of reactive torque because the drilling assembly continuously rotates. As a result, the bit can be much more aggressive. The SRB design has re-duced the back rake of the PDC

efficiency and ROP with steerable rotary systems.

High durability Optional DiamondBack* cutters provide a secondary cutting structure that improves the ability of the PDC bit to drill faster and further into harder, more abrasive formations. These durable cutters provide higher localized cutter density on the critical shoul-der area to extend bit life. As a result, tor-que response is smoother, which improves stability and control when drilling longreach or tortuous well paths.

Optimum hydraulic design SRB bits are designed to meet the specific hydraulic requirements of steerable rotary systems. By providing the pressure drop these systems require, the SRB design makes more effective use of the available hydraulic horsepower. The large junk slot area and open face volume of the SRB design significantly reduce reworking of cuttings to increase efficiency and ROP. In addition, the large open face volume allows the

silicate muds, for an advantage in applications where swelling formations are a concern.

Reed-Hycalog enhances bit performance with leadingedge technology Reed-Hycalog, a Schlumberger company, is a global provider of drilling solutions. Featuring Reed roller cone and Hycalog diamond bit technologies, Reed-Hycalog offers a wide range of bits to meet the requirements of your drilling application. To learn more about the advantages Hycalog Steerable Rotary Bits can provide in your drilling program, or for information on any Reed-Hycalog drilling bit, please contact your Reed-Hycalog representative. Eastern Hemisphere Headquarters Stonehouse, England Phone: 44-1-453-826061 Fax: 44-1-453-825833 Western Hemisphere Headquarters Houston, Texas USA Phone: 713-934-6600 Fax: 713-934-6609

Legal Information © 2000 Schlumberger Limited.

DAILY REPORT To :

Attention of :

Fax/e-mail/address

WELL INFORMATION Well :

Rig :

Planned TD:

Date :

Report No :

Days :

AFE No :

Operator interest : CI

RT - MSL (ft) Water Depth (ft, MSL)

MD

TVDSS

Cost to date (STG) :

WI

AFE (STG)

:

Final Rig Co-ordinates UTM Zone, CM Longitude : UTM (E) :

Latitude : UTM (N) :

Status at 0600 hrs MD

TVDSS

Progress (24 hr)

Hole size

Current formation

MD

TVDSS

LOT/FIT (identify which)

Present Operation :

CASING OD

OPERATIONS SUMMARY (last 24hrs)

Mud type : MW :

Vis :

Bit type : Weather :

PLANNED OPS (next 24 hrs)

FL : Motor : Wind :

Cl :

O/W : MWD : Seas :

GEOLOGY Lithology

ROP (ft/hr)

GAS Interval

TG %

C1 ppm

C2 ppm

C3 ppm

iC4 ppm

nC4 ppm

SHOWS PORE PRESSURE Est. pore pressure at current TD : Max. est. pore pressure in open hole : STRATIGRAPHY Formation Tops

Prognosed (ft) MD TVDSS

SURVEY DATA Depth Inclination

REMARKS

Azimuth

at MD :

Actual (ft) MD TVDSS

TVD

TVDSS :

ft High/ Pick method :-Cuttings/ Low MWD/Wireline etc

Vert Section

N/S

E/W

Daily Geology Report CONFIDENTIAL Well: 28/05/02

Report Date: 28/05/02

Report No: MBS-22

Status at 06.00 hrs (1st January) Current Depth ft MDBRT ft (-TVDSS) Formation Operation: 9560 ft -9474 ft Butler Fm. Wireline logging Operations Update 00.00 to 06.00 hrs: Pumped out from 8938 ft, tool plugged after pumping 30 litres. Pumped out from 8936ft, plugged after 27 minutes of pumping, correlation log for sample at 8664 ft, pumped out from 8664 ft for 1.5 hrs, o/w ratio was 50/50, aborted sampling since 95% pure sample could not be obtained. Attempted sample at 8561 ft, aborted sampling after dry pretest. Attempted sample at 8563 ft, aborted sampling after MDT tool plugged. Attempted sample at 8559 ft, aborted sampling after dry pretest. Attempted sample at 8600 ft, aborted sampling after MDT tool plugged. Pull out of hole for inspection of tool & servicing. Lithology Update: no new lithology Interval Descriptions Update: (Penetration Rate, Lithology, Oil Shows) Interval (ft) MDBRT

ROP (ft/hr)

Lithology, Oil Shows

No new lithology Drilling Gas Indications Update: Type Interval ft Background No new drilling Peaks Survey Data Update: Survey MDBRT (ft) None to Report

Total %

TVD BRT (ft)

C1 ppm

Inclination deg

C2 ppm

Azimuth Deg

C3 ppm

North (+ ft)

C4 ppm

East (+ ft)

C5 ppm N/A

Vert. Sect. (ft)

st 24 hour Operations Summary 00.00 to 24.00 hrs (to midnight on 31 Dec) Midnight Depth: 9560 ft MDBRT, -9474 ft TVDSS Drilled Interval: none Progress: 0 ft Summary: Continue running in with MDT, stabilize tool temperature at 8565 ft, conduct pressure tests: 49 attempted, 26 pressures, 16 dry, 7 lost seals, POOH w/ MDT. Wash & flush MDT probe, rigged up additional sampling modules, RIH to 8450 ft. Perform stick tests & allow tool to warm up, pull correlation log, sample at 8468 ft, pumped out 39.7 litres and filled 1 gal sample chamber. Correlate for sample at 8938 ft.

Drilling Data: Country: UKCS Spud Date: 1 Dec 2001 Well Data: Hole Size: 12 ¼” Drill Mode: Rotary Vis: 69

Block: 28/05 Days from Spud: 30

Last Casing: 13 3/8”@ 3322 ft Mud Type: KCL/Silicate WBM

pH: 11.7

Prospect: Calleva RT above MSL: 82ft

Rig: Borgny Dolphin Water Depth: 319 ft MSL

FIT 13.4ppg EQMW: M.W: 11.3 ppg F.L.3.3 cc/30min

Bit Type: BB657XA E.C.D: 11.6 ppg Cl: 59k mg/l

Stratigraphy: Formation Tops Top Tor Formation Top Hod Formation Top Herring Formation Top Plenus Marl Top Hidra Formation Top Rodby Formation Top Sola Formation Top Valhall Formation Top Kimmeridge Clay Fm. Top Calleva Sandstone Top Heather marker Top Sgiath Formation

Actual (ft) MDBRT 3361.0 3601.0 4765.5 5103.5 5140.0 5381.0 5649.0 6454.0 7983.0 8548.0 9100.0

Actual (ft) -TVDSS -3279.0 -3519.0 -4683.5 -5021.5 -5058.0 -5299.0 -5567.0 -6372.0 -7901.0 -8465.0 -9016.3

Prognosed (ft) –TVDSS -3280 -3510 Not Picked -5020 -5075 -5230 -5330 -6405 -7930 -8537 -9021 -9250

1

Hi(-)/Lo (+) (ft)

Pick Criteria

-1.0 +9.0

GR/Cuttings Cuttings/GR GR/Cuttings GR/Cuttings GR/Cuttings GR/Cuttings Cuttings/GR Cuttings/GR/ROP Cut./GR/ROP/Gas ROP/Cut./Gas/Torq GR (LWD memory data) Absent

+1.5 -17.0 +69.0 +237.0 -33.0 -29.0 -72.0 -4.7

Base Upp. Jurassic TD

9415.0 9560.0

-9329.6 -9473.5

-9511 -9641

-181.4 -167.6

GR (LWD memory data) 130 ft below base U. Jur.

WIRELINE Formation Tops Top Ekofisk Top Tor Formation Top Hod Formation Top Herring Formation Top Plenus Marl Top Hidra Formation Top Rodby Formation Top Sola Formation Top Valhall Formation Top Kimmeridge Clay Fm. Top Calleva Sandstone Top Heather marker Top Sgiath Formation Base Upp. Jurassic TD

Actual (ft) MDBRT 3150 3350 3856 5001 5138 5146 5396 5656 6160 7996 8560 9110

Actual (ft) -TVDSS 3067.8 3267.8 3773.8 4918.8 5055.8 5063.8 5313.8 5573.8 6077.8 7913.4 8476.9 9026.3

Hi(-)/Lo (+) (ft)

Pick Criteria

9431 9575

9345.5 9488.4

Prognosed (ft) –TVDSS No prognisis -3280 -3510 No prognosis -5020 -5075 -5230 -5330 -6405 -7930 -8537 -9021 -9250 -9511 -9641

~ -12.2 +263.8 ~ +35.8 -11.2 +83.8 +243.8 -327.2 -16.6 -60.1 +5.3 Absent -165.5 -152.6

Wireline logs Wireline logs Wireline logs Wireline logs Wireline logs Wireline logs Wireline logs Wireline logs Wireline logs Wireline logs Wireline logs Wireline logs Wireline logs Wireline logs Wireline logs

Interval Descriptions: (Penetration Rate, Lithology, Oil Shows) Interval (ft) MDBRT

ROP (ft/hr)

Lithology, Oil Shows

No new lithology Drilling Gas Indications: Type Interval ft Background None Peaks None Connection/Trip Gas Indications: Type Interval ft Trip None Connection None LWD Tool data: Tool Name

Total %

C1 ppm

C2 ppm

C3 ppm

C4 ppm

C5 ppm N/A N/A

Total %

C1 ppm

C2 ppm

C3 ppm

C4 ppm

C5 ppm N/A N/A

Directional sensor (ft)

GR Sensor (ft)

Resistivity (ft)

Neutron (ft)

Temp (°F)

East (+ ft)

Vert. Sect. (ft)

Not applicable Survey Data: Survey MDBRT (ft) None

TVD BRT (ft)

Inclination deg

Azimuth deg

Remarks: Regards Jamie Cureton Wellsite Geologist Onboard Borgny Dolphin Stag geological Services Ltd.

End of Report

2

North (+ ft)

Wireline Logging Summary

12 ¼” Hole Section

Calleva 28/05/02

Total Depth 9560 ft Casing 3320 ft

Start Time

Stop Time

Elapsed Time

22:00 22:05 23:45

22:05 23:45 0:40

0:05 1:40 0:55

0:40 1:20 1:30 4:10 4:30 6:40 7:40 8:00 8:15 9:15 9:30 10:30 10:45 12:18 12:20 12:38 12:40 12:47 12:49 12:57 13:01 13:10 14:25 15:15 16:32 16:37 16:42 16:45 17:10 17:15 17:20 19:00 20:30 21:10 21:30 23:24 23:34

1:20 1:30 4:10 4:30 6:40 7:40 8:00 8:15 9:15 9:30 10:30 10:45 12:18 12:20 12:38 12:40 12:47 12:49 12:57 13:01 13:10 14:25 15:15 16:32 16:37 16:42 16:45 17:10 17:15 17:20 19:00 20:30 21:10 21:30 23:24 23:34 0:00

0:40 0:10 2:40 0:20 2:10 1:00 0:20 0:15 1:00 0:15 1:00 0:15 1:33 0:02 0:18 0:02 0:07 0:02 0:08 0:04 0:09 1:15 0:50 1:17 0:05 0:05 0:03 0:25 0:05 0:05 1:40 1:30 0:40 0:20 1:54 0:10 2:18

0:00 1:50 13:24 15:30 16:00 16:45 17:00 19:25 21:00 21:15 23:10 23:35

1:50 13:24 15:30 16:00 16:45 17:00 19:25 21:00 21:15 23:10 23:35 0:43

1:50 11:34 2:06 0:30 0:45 0:15 2:25 1:35 0:15 1:55 0:25 1:08

0:43 1:17 1:27

1:17 1:27 2:59

0:34 0:10 1:32

2:59 3:15 3:36 3:45 4:45 6:40 7:10 8:40 9:00 10:00 11:00 11:25 11:55 12:03 12:45 12:52 13:00 16:15

3:15 3:36 3:45 4:45 6:40 7:10 8:40 9:00 10:00 11:00 11:25 11:55 12:03 12:45 12:52 13:00 16:15

0:16 0:21 0:09 1:00 1:55 0:30 1:30 0:20 1:00 1:00 0:25 0:30 0:08 0:42 0:07 0:08 3:15

Wireline Activity 29th December 2001 toolbox talk begin rig up of Run #1: SP-DSI-HRLA-PEX toolbox talk for next crew 30th December 2001 check toolstring load RA sources RIH on bottom, repeat pass main pass at casing shoe finish GR log unload RA sources finish after cals, Max Recorded Temps: 182, 181 degF finish rigging down Run #1, head changed, wait on crane lifts begin rigging up Run #2 operational check tool string RIH with FMI-HNGS-CMR at 8940 ft, open caliper Run #2 pass 1: FMI-HNGS log up repeat section, 900 fph, all buttons active at 8700 ft, close calipers RIH to 9250 ft, open calipers log up main pass, 900 fph, pad press. 17%, every 2nd button on one pad & flap inactive abort log at 9160 ft, close caliper & RIH to 9250 ft, to try again log up main pass 2nd attempt, 900 fph, pad press. 50%, same pad/flap problem at 8200 ft, stop log, retract arms, RIH log up main pass Run #2 pass 2: CMR after tuning tool, 850 fph stop log at 8200 ft, RIH to 8732 ft, tune CMR RIH to 8850 ft start repeat section at 8778 ft end repeat section & drop down to 8732 ft to tune tool tune CMR POOH perform after cals, rig down FMI-HNGS-CMR, MRT 183, 182 degF rig down FMI-CMR complete rig up Run #3: MDT pressure tests RIH Turn on motion compensator stick test 1st correlation pass 31st December 2001, New Year's Eve stabilize temperature of MDT tool in hole at 8565 ft MDT pressure profile. 49 pressures attempted, 26 obtained, 16 dry tests, 7 lost seals POOH with MDT, Pressure survey completed wash down & flush out single probe rigged up additional MDT sampling modules to run #3 MDT tool surface check Run #4: MDT samples RIH to 8450 ft perform stick tests & allow, MDT to warm up correlation log to position for sample at 8468 ft Pumped out 39.7 litres and filled 3.74 litre sample chamber at 8468 ft with water correlation log to position for sample at 8938 ft Pumped out from 8938 ft, MDT tool plugged up after pumping 30 litres 1st January 2002, New Year's Day Pumped out from 8936 ft, MDT tool plugged up after pumping 27 mins of pumping correlation log to position for sample at 8664 ft pumped out from 8664 ft. After pumping for 1.5 hrs O/W ratio was 50/50. Aborted sampling since a 95% pure sample could not be obtained. Attempted to sample at 8561 ft, Aborted sampling after dry pretest Attempted to sample at 8563 ft, Aborted sampling after MDT tool plugged Attempted to sample at 8598 ft, Aborted sampling after dry pretest Attempted to sample at 8600 ft, Aborted sampling after MDT tool plugged Pull MDT tool out of the hole for inspection & servicing Turn off motion compensator, toolbox talk drain SC#1, sample from 8468 ft, volume 3750 psi probe plugged, took 3000 psi to clear, service tool begin making up MDT toolstring for run #5 surface check Run #5: MDT samples operational check Set compensator, RIH correlation run for sample at 8563 ft, add 3.5 ft Attempt sample at 8563 ft, aborted as sample not cleaning up above 50% oil Attempt sample at 8620 ft, telemetry failure, tool retracted automatically. Drop down to 8635 ft, no communication with tool. POOH, found short in cable head, rehead, lay out MDT (program cancelled) Rig up Run #6: VSI

Page 1 of 1

9125.0

9118.0

8873.9 9111.9

9106.0

9101.0 9087.0

9070.0

9050.0 8934.0

1

2

3 4

5

6 7

8

9 10

misfire 0.8

0.6

misfire 0.8

0.6

misfire 0.6

0.8

1.0

Length (ins)

good

~

~

~

~

~

~

Shows

20/06-4

Well Name:

Depth (ft)

60

Total Attempted

Core No.

8

Run Number

fairly strong hydrocarbon

~

~

~

~

~

~

Odour

light brown uniform

~

~

~

~

~

~

Stain

moderate to bright yellow gold

~

~

~

~

~

~

Natural Fluor

Described by:

Recovered

Diameter

immediate weak diffuse white, moderate bluish white blooming

~

~

~

~

~

~

Cut Fluor

very slight discolor -ation

~

~

~

~

~

~

very weak yellow brown / bright bluish white

~

~

~

~

~

~

Residue: UV / white

Coring Contractor

Empty

Cut Colour

Martin Butler

43

Formation

sandstone

shale

shale

shale

shale

shale

shale

Lithology

Hole Size

Lost Bullets

Date

12¼”

0

3rd May 2002

dark greyish orange to grey brown, unconsolidated, firm to hard, induration altered by bullet impact, very fine to dominantly fine grained transparent and occasionally translucent quartz, angular to subangular, very rarely very well rounded and frosted grains, rare moderate green glauconite and siliceous white cylindrical microfossil debris, weak calcareous cement, very good intergranular porosity

medium dark brownish grey, firm to moderately hard, moderately calcareous, generally slightly silty with frequent very fine grained mica, subfissile medium dark brownish grey, firm to moderately hard, moderately calcareous, very slightly silty and micromicaceous, traces of disseminated pyrite, subfissile to fissile

dark grey to dark brownish grey, firm, very calcareous, slightly silty and micromicaceous, subfissile medium dark brownish grey, firm, very calcareous, generally slightly silty and micromicaceous, with moderately silty laminae containing frequent very fine to fine grained muscovite, subfissile to fissile, earthy texture

dark grey, firm, slightly silty and micromicaceous, very calcareous, fissile dark grey, firm, slightly silty, very calcareous, trace mica, rare calcite healed microfractures, occasional greasy lustre, fissile

Core Description

Schlumberger

2

Kimmeridge, Calleva Sst

SIDEWALL (CST) CORE REPORT

CORING DECISION SUMMARY WELL NAME

05/28/2002

GEOLOGIST

M. Butler

DATE

12/16/2001

TIME START/ FIN

3:25

8548/-8465

CURRENT DEPTH

8560/-8477

DRILLING DATA DEPTH DRILL BREAK (mddbrt/ mtvdss)

(mddbrt/ mtvdss)

LENGTH OF BREAK

12ft

ROP Pre-break (ft/hr)

25 - 35

ROP during break (ft/hr)

66 - 105

Torque Pre-break (klbs)

6-8

Torque during break (klbs) 8 - 9

Mud weight in (ppg)

11.3

Mud weight out (ppg)

ECD (ppg)

11.6

Estimated O/B ppg

8.7

Pit gain (bbl)

None

Controlled drilling?

Yes - using WOB

Est pore pres Pre-break

8.7

Est pore pres during break 8.7

11.3

GEOLOGY Lithology after circulating

40% Sandstone

bottoms up

60% Siltstone

Visible porosity Nature of cuttings, e.g.

Sandstone: generally loose, locally well cemented

angular, loose grains, size, Siltstone: normal subblocky shape SHOW DESCRIPTION FLUIDS Oil/ condensate stain

Fluorescence Light brown

colour

moderate yellow

bleed

% of sample

100

colour

intensity (weak, etc.)

Moderate

wax

cut fluor colour

Blue white

live

cut speed

slow to moderate

cut colour and stain

crush cut fluor colour

Blue white

crush cut speed

solvent used

Isopropanol

crush cut colour and stain GAS Pre-break

From break

Total gas

0.35

Total gas

(0.35 b'grnd) 1.35 peak

C1

1355

C1

4314

C2

157

C2

649

C3

136

C3

975

iC4

28

iC4

108

nC4

41

nC4

421

C5

N/A

C5

N/A

H2S

0

H2S

0

CO2

N/A

CO2

N/A

2

Shows

Good

V. Good

None

None

Depth

8703.5

8733.45

8763.75

8795.65

None

None

V. Strong

Strong

Odour

8675 – 8798ft Cored Interval Well Name: 28/05/02

Core Number

CORING REPORT 123ft

5 1/4

None

None

Light brown

Light brown

Stain

None

None



Natural Fluor

None

None



Cut Fluor

Silty Claystone

Silty Claystone with Sandstone Stringers

Coarse Sandstone

Coarse Sandstone

Coring Inc.

8675.0 – 8795.65ft

Calleva Sand

Recovery

Recovered

Date

98.1%

120.65ft

20/12/01

Colourless, light brown (oil stain), rarely dusky yellow green, locally white, moderately to very friable, crumbly, predominantly quartz, locally quartzite lithoclasts, rare carbonaceous fragments, medium to coarse, locally very coarse, subrounded, locally subplaty, locally subelongate, poorly sorted, very poorly cemented with calcite. 5-10% visible intergranular porosity, strong hydrocarbon odour, slow oil seepage, uniform bright yellow orange fluorescence, fast streaming blue white cut, instantaneous blue white crush cut, light brown residual ring. Colourless, light brown (oil stain), rarely dusky yellow green, locally white, moderately to very friable, crumbly, predominantly quartz, locally quartzite lithoclasts, rare carbonaceous fragments, medium to coarse, locally very coarse, subrounded, locally subplaty, locally subelongate, poorly sorted, very poorly cemented with calcite. 5-10% visible intergranular porosity, very strong hydrocarbon odour, slow oil seepage, uniform bright yellow orange fluorescence, fast streaming blue white cut, instantaneous blue white crush cut, light brown residual ring. Silty Claystone with interbedded calcareous Sandstone with slumped margins Silty Claystone: Olive black to green black, hard, fractured, abundant slickensides, blocky, locally micaceous, locally pyritic, slickenside fractures filled with fibrous and crystalline calcite, also traces of oil, locally there are more massive calcite veins, locally moderately calcareous. Sandstone: White, colourless, hard, none friable, blocky to subangular, fine, quartz, subangular to subrounded, subspherical, very well cemented with calcite, locally streaked with pyrite veins. Shows slumping structures into Claystone below. Medium to dark grey black, locally green black, hard, subfissile, micaceous, locally slightly pyritic, abundant carbonaceous macro fossils fragments, none calcareous, locally micro lenticular calcite veins.

Core Description

Coring Contractor

Rec. Interval

Formation

Lithology

Described by: Jamie Cureton

Total Cut

Diameter

CORELOG WELL INFORMATION

EQUIPMENT

Company

Core BBL Type & NO:

HT 60

Core no:

PERFORMANCE 2

Contractor

Core BBL Size

180'X 9 1/2" X 5 1/4"

Interval Cored-FFinish

8798

Ft

Rig Name

I.T. Type

JAMBUSTER

8,675.0

Ft

Well No

Stab. Size

12 7/32"

Amount Cored

123.0

Ft

Field

L. Shoe & Catcher

PILOT SHOE & SPRING

Core Recovery

120.7

Ft

Area

Bit Style & Size

RC 478 C3 12 1/4" X 5 1/4"

% Recovery

98%

%

Hole Temp

Bit ser #

322935

Coring Hours

30.70

Hrs.

Hole Size

TFA

1.06

ROP

4.01

Ft/hr

Hole Angle

IADC Dull Grade-Start

0/0/NO/A/X/IN/PN/PR

Reaming

WASHED/REAMED LAST STAND

Start

Formation

IADC Dull Grade- Finish 3/7/WT/N&T/X/IN/CT/PR

Service Engineer Name

TOM/JOHN

Lithology

SPP on/off bottom

725--1000

Date

18/19-12/01

Liner Size

6 1/2"

Remarks

Mud Type

K/CL

WT.PPG

11.3

WL

SPM 2%

% Solids

Tr

6.8

GPM LCM

200--400

n/a

OPERATING PARAMETERS

8,675

8,675

8,675

8,680

8,680

8,680

8,680

8,685

8,685

8,685

8,685

8,690

8,690

8,690

8,690

8,695

8,695

8,695

8,695

8,700

8,700

8,700

8,700

8,705

8,705

8,705

8,705

8,710

8,710

8,710

8,710

8,715

8,715

8,715

8,715

8,720

8,720

8,720

8,720

8,725

8,725

8,725

8,725

8,730

8,730

8,730

8,730

8,735

8,735

8,735

8,735

8,740

8,740

8,740

8,740

8,740

8,745

8,745

8,745

8,745

8,745

8,750

8,750

8,750

8,750

8,750

8,755

8,755

8,755

8,755

8,755

8,760

8,760

8,760

8,760

8,760

8,765

8,765

8,765

8,765

8,765

8,770

8,770

8,770

8,770

8,770

8,775

8,775

8,775

8,775

8,775

8,780

8,780

8,780

8,780

8,780

8,785

8,785

8,785

8,785

8,785

8,790

8,790

8,790

8,790

8,790

8,795

8,795

8,795

8,795

8,795

8,680 8,685 8,690 8,695 8,700 8,705 8,710 8,715 8,720 8,725 8,730 8,735

Prepared By Billy Roy

120

100

80

40

20

0

50

45

40

35

30

25

20

10 15

5

0

8,675

60

RPM

WOB Klbs

10

8

6

4

2

0

TORQUE Kft.lbs 1200

1000

800

600

0

200

70 80

50 60

30 40

10 20

0 8,675

400

PRESSURE psi

ROP Ft/hr

Biostratigraphic and Palaeoenvironmental Analysis of Core Samples from Wells 1 and 2, Caspian Sea. [A FICTICIOUS REPORT BASED ON AN ACTUAL CLIENT-REPORT SUBMITTED IN WEB-READY FORMAT] by Michael D. Bidgood MSc PhD Michael D. Simmons PhD Patrice A.R. Brenac MSc GSS International Unit 39, Howe Moss Avenue Kirkhill Industrial Estate Dyce, Aberdeen, UK AB21 0GP

date Prepared For: client's name address This report presents and discusses the results of micropalaeontological and palynological analysis of core samples from 2 unnamed wells. Samples were collected from cores laid out at ?? Ltd., Aberdeen on a number of different visits. The following depths (in metres) were sampled and analysed: Well 1

Well 2

depths confidential

depths confidential

The aims of this study were: i. ii.

To provide information on the environment of deposition of the sediments from these cores, the sediments being reservoir intervals. To provide information on the age and biozonal potential of the sediments for future correlation to other wells and to place the sediments in a regional context.

Within this site-report, the methodology of the study is outlined, followed by a discussion of the results. All the raw palaeontological data pertaining to the study is included within the Enclosures of the paper copy of this study. However images of the stratigraphic summary logs are included on this web site. This site-report includes a summary of conclusions and recommendations for future work. Personnel involved with this project were:

Dr. Michael D. Simmons : project co-ordination, integration, regional geology Dr. Michael D. Bidgood : micropalaeontological analysis Mr. Patrice A.R. Brenac : palynological analysis

Summary Management Summary Drawing on the experience of previous biostratigraphic studies in the South Caspian Basin, 32 samples from reservoir intervals within the Red Coloured Series of wells 1 and 2 were studied for their palynomorph and calcareous microfossil content in order to provide information on environment of deposition and potential biostratigraphic subdivision. The results are encouraging in that it has been possible to determine that all the studied sediments were deposited in a fluvial environment with samples from well 2 showing evidence for periods of standing water between somewhat more meandering rivers/streams in a more low relief distal setting compared with 1, perhaps delta plain as opposed to alluvial plain. Samples from well 1 shows evidence for a constantly flowing freshwater river/stream system with little or no apparent standing water bodies (lakes, ponds etc.). The change in depositional setting between wells 2 and 1 (which is stratigraphically higher) suggests a prograding deposition system. Fingerprinting of various stratigraphic intervals is possible using changes in palaeoclimate (and hence vegetation belts) reflected in the in situ palynomorph assemblages, coupled with variations in the pattern of reworking of palynomorphs. The potential for biostratigraphic correlation now needs to be tested by examination of the same stratigraphic intervals (reservoir zones) in other adjacent wells.

Methodology The sediments sampled from the cores from wells 1 and 2 are from the "??? Series", the major hydrocarbon reservoir interval in the ?? part of the South Caspian Basin. The cores are from reservoir zones within the ?? Series and it is known that the cores from well 1 lie stratigraphically above those from well 2. Regional data (Jones & Simmons, 1996) indicates that the ?? Series is essentially Pliocene in age. For the coeval "Productive Series" sediments on the western (Azerbaijani) side of the South Caspian Basin, preliminary studies (Zubakov & Borzenkova, 1990; Jones & Simmons, 1996; Reynolds et al., 1997) have indicated that biostratigraphic subdivision of these sediments is possible using changes in palynomorph assemblages which can be related to high frequency changes in palaeoclimate. Coupled with this, a broad biostratigraphic subdivision is possible using changes in ostracod assemblages and changes in the pattern of reworking of

microfossils found within the sediments (Khalilov, 1946; Agalarova, 1956). It was hoped that such biostratigraphic subdivisions could be applied to the ?? Series sediments from the wells of this study, and biostratigraphically "fingerprint" individual reservoir zones, thus assisting in future correlation studies. Additionally, information on palaeoenvironments was sought. It is well known (Jones & Simmons, 1996; Reynolds et al., 1997) that the ?? Series represents the deposits of the large delta of the Palaeo-Uzboy (= Palaeo-Anu Darya) river which flowed into the South Caspian Basin during the Pliocene. However, less clear is the precise palaeoenvironment that local sediments represent. Given that ostracod faunas are known to occur within the ?? Series (Agalarova, 1956), and these assemblages of these fossils often have useful palaeoenvironmental significance, it was hoped that by coupling micropalaeontological and palynological studies with the sedimentological studies being carried out in the cores that some reasonably detailed information on palaeoenvironments could be obtained. Given the aims of the study and the background noted above, 32 of the more muddy intervals (i.e. those most likely to have recovery of microfossils and palynomorphs) were sampled and then processed and analysed for palynology and calcareous microfossils.

Discussion General Remarks Microfossil recovery from the samples studied is highly variable. In well 1 assemblages of calcareous microfossils are relatively poor with only sparse reworked Cretaceous and Tertiary microfossils being recorded. In well 2 a few cores yielded some in situ ostracods and charaphytes. Palynomorph recovery was also variable and is dominated by reworked taxa. However, many samples yield enough in situ taxa to make some comments on palaeoenvironment, palaeoclimate and biostratigraphy. Although, the more muddy intervals from the cores were selected for sampling and analysis, it should be noted that many of these samples could not be termed mudstones. Rather they were siltstones or fine sandstones. Typically microfossil and palynomorph recovery is relatively poor in such lithologies. Palaeoenvironment The overall palaeoenvironmental setting for the two wells is within a fluvial system with sediments from well 1 relatively proximal to source and well 2 in a more distal (i.e. the overall succession represents progradation – sediments from well 2 are known to be stratigraphically below those of well 1), yet still within the non-marine part of the overall system. No "marine" indicators are noted, even accounting for the low/non-salinity of the Caspian Basin at the time of deposition. The overall climate was warm and dry (but see possible subdivision below), with a notably low proportion of conifer-derived pollen. Samples from well 1 shows evidence for a constantly flowing freshwater river/stream system with little or no apparent standing water bodies (lakes, ponds etc.), as shown by the lack of fungal spores and ostracods.

Samples from well 2, with more prominent fungal spore and ostracod recovery, shows evidence for periods of standing water between somewhat more meandering rivers/streams in a more low relief distal setting compared with well 1, perhaps delta plain as opposed to alluvial plain. Some palaeoclimatic signatures can also be picked out. These include samples with common non-arboreal herbaceous taxa (e.g. Echitricolporites spinosus and Fenestrites spinosus) which are thought to represent occurrences of low lying vegetation in a relatively warm, dry, open landscape – perhaps steppe-like conditions. These appear to alternate with samples with common arboreal taxa (e.g. Inaperturopollenites spp.) which indicate a more forested landscape – again with relatively dry, warm temperatures. These two types of assemblages can be seen from the following intervals: Well 1 ???m - ???m: mixed steppe & forest ???m - ???m: steppe ???m: forest ???m: forest ???m (*): mixed steppe & forest Well 2 ???m - ???m: steppe ???m: ?forest ???m - ???m: forest ???m - ???m: forest (*) The sample at ???m also contains common Pteridophyte (fern) spores (e.g. Deltiodospora spp.) and palm-like pollen (e.g. Psilamonocolpites spp.) which together suggest more humid conditions associated with the arboreal taxa over this interval. Samples suggestive of standing water bodies are noted only from well 2. These are picked out by the presence of abundant fungal spores, common ostracods and sporadic charaphytes (Chara spp.) and include the intervals/samples: ???m ???m (though with no ostracods recorded) ???m - ???m ???m - ???m (though with no ostracods recorded)

The reduced amount of gymnosperm pollen in the well 2 material may also reflect a broad meandering fluvial depositional environment, where the amount of these taxa is diluted by the presence of large amounts of other palynomorphs. Biostratigraphy The overall age of the section as indicated by the in situ taxa is Pliocene (undifferentiated). However, potentially local correlative events can be picked out by a. the in situ assemblage patterns reflecting climatic signatures b. the pattern of reworking These, in turn, can potentially be used to "fingerprint" discrete reservoir units and consequently as a correlation tool for those units. Zubakov & Borzenkova (1990) and Jones & Simmons (1996) have demonstrated that during the Pliocene, high frequency alternations between glacial and inter-glacial conditions affected the climate of areas which were the source of sediments in the South Caspian Basin (such as those in the well 1 and 2 cores). Climate belts and thus vegetation belts moved with changes from glacial to interglacial conditions. In the well 1 and 2 cores glacial conditions are represented by forest-dominated palynomorph assemblages and interglacial conditions by steppe-dominated assemblages. The table given in the palaeoenvironments section above shows that certain stratigraphic intervals have a particular climate-related palynomorph assemblage. This may prove useful in correlating these intervals to other wells in the nearby area and in the South Caspian Basin. Reworking shows some potentially useful variation, with the proportion of Palaeogene vs. Cretaceous reworking of palynomorphs being moderately variable. Of particular note is sample well 2; ???m which is completely dominated by Cretaceous spores (so much so it has all the appearance of really being Cretaceous!). This can be contrasted with samples such as well 1; ???m and well 2; ???m which are very rich in Palaeogene dinoflagellates. The potential climatic signatures and reworking patterns to provide biostratigraphic correlation needs to be tested by examination of the same stratigraphic intervals (reservoirs zones) in other adjacent wells.

Conclusions 1. Both the sets of samples from wells 1 and 2 represent deposition in a fluvial system. 2. Samples from well 1 show evidence for a constantly flowing freshwater river/stream system with little or no apparent standing water bodies (lakes, ponds etc.). 3. Samples from well 2 show evidence for periods of standing water between somewhat more meandering rivers/streams in a more low relief distal setting compared with well 1, perhaps delta plain as opposed to alluvial plain. The change in depositional setting between 2 and 1 (which is stratigraphically higher) suggests a prograding deposition system. These results are in keeping with what

is generally known about the progradation of the Palaeo-Uzboy into the South Caspian Basin during the Pliocene. 4. The samples are of Pliocene age. Fingerprinting of various stratigraphic intervals is possible using changes in palaeoclimate (and hence vegetation belts) reflected in the in situ palynomorph assemblages, coupled with variations in the pattern of reworking of palynomorphs. 5. The results from this study given encouragement to the use of biostratigraphy (palynology and calcareous micropalaeontology) in future studies of wells from the area and/or wells sampling the ?? Series elsewhere in the region. The fossil assemblages have proved themselves useful in determining environment of deposition (with implications for reservoir architecture, connectivity, etc) and for providing a fingerprint of reservoir zones which can be used to assist in well to well correlation within and outside the immediate area by providing a check of wireline log correlations.


Wellsite Geological Processes

Stag Geological Services Ltd. Reading UK

Revision D January 2008

Introduction to Mudlogging Introduction Hydrocarbon exploration begins with basin studies and geochemical, magnetic, gravity and seismic surveying on a grand scale which is further refined as information is gathered and processed. Potential hydrocarbon plays are developed as structures are interpreted and the models are finetuned. However, despite major advances in exploration processes over the years, the development of 3D and 4D seismic and visualisation software prospects still have to be drilled to confirm the presence of oil and gas in sufficient quantities with suitable reservoir conditions to promote development plans. The exploitation process still requires the drilling of boreholes to physically extract the hydrocarbons from their reservoir rocks. During the drilling of exploration, appraisal and development wells formation evaluation is required to: • Drill through the overburden to the target formation • Land the well in the optimum position in the target • Drill the reservoir section in the optimum manner • Call T.D. correctly However, the drilling practices that are necessary for the accomplishment of these ends often act as a barrier to the discovery of hydrocarbons. For example, in normal drilling it is essential that the hydrostatic pressure created by the density of the drilling fluid in the hole be sufficient to overcome the pressure exerted by the fluids in the formation; the alternative can be a costly and extremely dangerous kick or blowout. Yet this same overbalance causes filtration of the drilling fluids into the formations and pushes the formation fluids (where permeability exists) away from the wellbore. Thus the composition and concentration of formation fluids can be determined only with difficulty. Underbalanced drilling is an increasingly used process whereby the mud pressure is deliberately kept less than the pore fluid pressure in order to speed up drilling and minimise formation damage. Of course this requires sophisticated techniques, specialised equipment and highly trained personnel to be successful and is not within the scope of this document.


1-1

Introduction to Mudlogging Formation Evaluation It is necessary to have a group of methods and tools capable of locating and evaluating formations penetrated by the drill bit and their fluid content. We call the use and interpretation of these methods Formation Evaluation. Formation evaluation methods can be classified broadly according to whether they are used: • As drilling is in progress Drill Returns Logging Measurement While Drilling Coring and core analysis (although of course most analysis is post-drilling) • After the hole (or at least a portion of it) has been drilled. Wireline Logging Sidewall Coring Wireline Formation Testing Drillstem Testing Most of the above methods must be used together to complement the others; by themselves each has limitations and shortcomings.

Drill Returns Logging Drill Returns (or Mud) logging is the continual inspection of the drilling mud and cuttings for traces of oil and gas and, in part, serves as a primary lead to coring and testing. The Formation Evaluation Log or Mudlog is a graphical portrayal of this data. And contains such information as: • Depth/ROP • Cuttings Percentage Log • Total Gas and Chromatograph Data • Oil show information • Cored Intervals • Casing Points • Bit Data • Drilling Fluid Information • Sample Descriptions

1-2


Introduction to Mudlogging

Figure 1: Mud Logging Unit Drill returns logging has an added usefulness as a safety measure for the early detection of hazardous drilling conditions which could result in a blowout. Rates of penetration, the amount and type of recorded drilled gas and return mud flow variations are all routinely monitored in order to highlight any potential reductions in differential pressure (between the mud pressure and pore pressure). Drill Returns Logging was introduced as a commercial service in 1939. It provides continuous onsite inspection, detection, and evaluation of the rock units as they are being drilled with regard to potential oil and gas production. Correct methods of obtaining this data and its subsequent evaluation are very important factors in all exploratory programs, and their effectiveness depends primarily upon the wellsite geological team. Data collection is often performed by geological technicians called Mudloggers. Equipped with a field laboratory and drilling and formation evaluation sensors mudloggers are able to collect drill cuttings, lag them for their depth of origin and, mostly by means of visual inspection, record the key data of the formations penetrated and their contained fluids. Gas data is measured and recorded automatically.


1-3

Introduction to Mudlogging From bit to surface The crushed cylinder of formation which is drilled to make the hole is released into the mud stream. Once released, the formation and any contained fluids, gas or oil are carried to the surface by the mud. Mud logging largely becomes a matter of extracting this information in terms of restoring (recording on the Mud Log) the original in-place characteristics of the formation as much as possible. The first disturbance of the subsurface strata as a result of being drilled is that of varying amounts of flushing by the mud filtrate. Ordinarily, the drilling mud exerts a hydrostatic pressure on the formation in excess of the formation pressure. The formation serves as a filter medium upon which wall cake is deposited and through which the filtrate water permeates, flushing interstitial fluids away from the wellbore. On the bottom of the hole where new formation is being continuously exposed and wall cake is not permitted to accumulate, the rate of filtration of mud fluids is always at a maximum. Factors that affect the amount of oil and gas remaining in the formation after flushing and which, in turn, affect the amount of oil and gas entrained in the drilling mud are listed below. • Depth • Rate of Penetration • Size of hole • Volume of drilling fluid circulated • Physical properties of the formation • Properties of the drilling mud It is reasonable to assume that formations have often been flushed to the extent of being completely depleted of producible hydrocarbons before being drilled, though more often flushing will be to a lesser degree than this. After undergoing flushing, the formation is subjected to the bit action, being released into the mud stream in the form of rock chips or cuttings. These are subjected to the dynamic hydrostatic pressure of the mud column. During their travel time from the bottom of the hole to the surface, the cuttings undergo a normal production cycle in that the pressure on them, caused by the hydrostatic pressure of the mud, is reduced to atmospheric. Gases, if present, and liquids (to a lesser degree) expand due to this pressure reduction and cause the cuttings to release into the drilling mud any fluids which they contained permeability permitting. Thus, upon reaching the surface, the cuttings will have been depleted, either by flushing or produc-

1-4


Introduction to Mudlogging tion. For this reason a great deal of importance is placed on the hydrocarbon content of the mud as the source of the information for evaluating the productive possibilities of the formation being drilled. The fluids released from the cuttings and conveyed to the surface by the mud are the basis for several measurements by well logging instruments and methods. These readings are important considerations in the continuous evaluation of the productive possibilities of the formation as it is being penetrated. This is not to discount the importance of cuttings in formation evaluation. The cuttings are samples of potential reservoir rock. Aside from their importance as a basis for correlation and stratigraphic purposes, they afford the means of the first study of the reservoir characteristics of the formation. However, they must be studied and evaluated, bearing in mind that they may have been extensively flushed and produced.

Figure 2: Mud Logging Unit Interior

The Formation Evaluation Log Mud Logging is not complex in principle and does not interfere with the drilling process, and the results are available a short time after the rock has been drilled. The Mud Log is recorded simultaneously with the drilling of the hole. Detailed data on the physical characteristics of the subsurface strata is


1-5

Introduction to Mudlogging collected and analysed as it becomes accessible at the surface. This information is continuously evaluated, and control of certain phases of the drilling operation is exercised by the Operator based on the interpretation of the results. Besides almost immediately indicating the presence of any potentially productive zone, the mud log serves as a basis for modifying the drilling program efficiently and is an important corroborative and correlative tool. A comprehensive mud log contains the following information: • Total combustible hydrocarbon gases from the drilling mud • Chromatographic analysis for individual gas content (methane- pentanes) • Total combustible gas from drill cuttings • Oil from drilling mud and drill cuttings • Detailed rate of penetration curve • Lithology composition and description • (including estimated visual porosity) • Drilling mud characteristics • Data pertinent to the well’s operation coring points, trips for new bit, drillstem tests, bit data, carbide lag information, deviations, and other pertinent engineering information.

1-6



Figure 3: Formation Evaluation Log


1-7

Introduction to Mudlogging History and Development of Mudlogging As noted above Mudlogging developed in the 1930s as engineers and geologists began to realise that cuttings samples and released fluids could be tracked as they made their way to the surface carried by the drilling fluid. Estimations of the bit-to-surface travel time, the Lag Time, could be made by calculating the time taken for the mud to travel along the annulus, taking into consideration borehole geometry (the annular volume) and the volumetric discharge of the mud pumps. With accurate knowledge of lag time cuttings samples could be collected and lagged to their depth of origin thus enabling lithology and gas logs to be produced, plotted against depth.

Geology Initially mudlogging was very much a geologically oriented service with a two-man logging crew working 12 hour shifts (or tours) and thus relieving the rig crew of having to make ad hoc and, mostly, not very useful sample collections. In order to correctly lag the samples the mudloggers needed to have accurate and continually updated estimates of total depth (and therefore ROP) from reliable sensors. They also installed gas extraction machines in the ditch behind the shale shakers linked to a detection and analysis system via plastic tubing and a vacuum pump. This was routed to a container-sized laboratory or Mudlogging Unit which also housed cuttings sample washing, processing and testing equipment.

Figure 4: Safety Monitoring Mudlogging now gave the rig a new team of data collection and monitoring personnel equipped with a laboratory and sophisticated sensors. Whilst gas

1-8


Introduction to Mudlogging detection was initially concerned with formation evaluation its use for safety monitoring was growing in importance. Increases in gas readings at the surface could indicate changing bottom-hole conditions and the first indications of potentially unstable conditions. Thus the early mudloggers also took on a safety monitoring role, and could provide this around the clock whenever the borehole was not shut-in. Another prime, early warning sign of unstable bottom-hole conditions is mud pit volume monitoring. This still provides the rig crew with early indications of a kick developing. When formation fluids enter the borehole mud is displaced from the borehole and finds its way back to the storage tanks. This is a kick and, left to develop, could lead to these fluids reaching the surface in an uncontrolled manner which is termed a blow-out. For many years the mudlogging crew had much better electronic sensors for monitoring pit volume changes than rig crews and therefore this form of safety monitoring has always been a major part of mudloggers duties and responsibilities. Now that the rigs themselves have state-of-the-art data monitoring systems the mudloggers provide valuable back-up assistance.

Formation Pressure Evaluation Whilst the early detection of kicks via pit volume changes, increases in return flow and total gas readings remains vitally important, it was soon realised that if better knowledge of pore pressure and rock fracture pressure was acquired correct drilling optimisation could lower the number of kicks and blowouts that were occurring and make the whole operation much safer. Direct knowledge of pore pressure is available from wireline logging and production tests, although only after a portion of the well has been drilled and only in permeable rocks. If a kick is taken pore pressure can be calculated but of course this is not recommended drilling practice in order to find out the magnitude of the pore pressure. Pressure build up in clays and shales cannot be measured directly because of low permeability and therefore has to be estimated from indirect means. It is unlikely that a kick will develop in shales but high pressures in impermeable rocks can lead to severe drilling problems such as impaired hole cleaning and stuck pipe. It only needs a thin permeable stringer to produce a kick. Overpressure in clays often results from rapid loading and under-compaction resulting in a formation that has low density and high porosity compared with normally pressured rocks at the same depth. Geological or drilling engineering data that can identify under-compacted rocks can, therefore, help to recognise potentially overpressured rocks. Increases in gas levels, higher ROP, reduced shale density, low formation resistivity, longer sonic travel times, and lower than expected density values may all indicate increasing pore pressure in clays. In the late 1960s and early 1970s tech-


1-9

Introduction to Mudlogging niques were developed to use this information quantitatively to make indirect estimations of pore pressure while drilling. Mudlogging companies took on the lead role of performing this service but required access to drilling data in order, for example, to normalise ROP for the effects of changing WOB, RPM etc. Thus extra, drilling engineering, sensors were installed on the rig and wired up to the mudlogging unit linked to a computerised data acquisition system to store and process the information. Thus computerised mudlogging began in the early 1970s, primarily as a pressure evaluation enhancement to normal mud logging services. An experienced mudlogger (or pressure engineer) normally took on these duties leaving the sample collection and processing to the more junior of a now 2man logging crew.

Drilling Engineering Assistance As well as routinely collecting and processing geological data mudloggers now had access to a wealth of drilling engineering information; mostly still denied to the rig crew who, during the 1970s, were still mostly reliant on analogue chart recordings of basic drilling data. The collection of drilling data rapidly became another important part of the mudlogging service and with it the development of drilling engineering assistance software covering hydraulics optimisation, drilling efficiency, trip monitoring, kick and kill analysis and directional drilling applications. The modern mudlogging service now incorporates geology, safety monitoring, safety planning and drilling engineering assistance and is often the data collection and distribution hub of the rig or platform

1-10



Figure 5: Drill Returns Logging


1-11


1-12


Lag Time Lag Time Calculation When collecting drill cuttings it is necessary to relate them to their depth of origin in order to accurately compile the lithology log. Cuttings and released fluids are brought to the surface with the returning mud; by calculating the time taken for the mud to be circulated around the borehole the lag time can be determined. Hole cleaning, however, is not a totally efficient process. Even in vertical wells cuttings will slip through the mud and become sorted much as they would do when travelling in a river or stream. The cuttings slip velocity depends on mud properties, density and viscosity, and the size, shape, density and orientation of the solid particles. Gases will tend to permeate through the mud and may, therefore, arrive earlier than cuttings. Whilst recognising these limitations, however, cuttings lag time is normally referred to mud travel time. In high angle, ERD and horizontal wells hole cleaning can be very inefficient and accurate estimations of lag time can be very difficult. For example, in horizontal wells, the cuttings have only to slip a very small distance through the mud before collecting on the bottom of the hole. Calculations of lag time are based upon: • Annular Volume • Pump Output This provides a reasonably accurate estimation in cased hole but open hole sections may wash out leading to uncertainties about actual hole size. Calculations are normally supplemented with tracer tests or natural lag indications from drilling breaks.

Tracer Tests The lag can best be determined by placing a tracer in the drillpipe at the surface when the kelly or top drive is broken off at a connection. The tracer is pumped through the drillstring into the hole and back to the surface, and the number of strokes required of the circulating pump to make this circulation is determined. From this total pump stroke count, the number of strokes required to pump the tracer down the pipe to the bottom of the hole is subtracted. This figure is calculated on the basis of the capacity of the drillstring and the displacement of the circulating pump. The result is the lag time in pump strokes.


2-1

Lag Time Various materials (such as whole oats, rice, barley or lentils) may be used as tracers and picked up on the shaker screen for approximating the lag. Care needs to be taken when using solid tracers as downhole motors and MWD tools, for example, will have specific tolerances for the amount and size of solids that can be circulated through them. Mudloggers and Wellsite Geologists should check with the drilling engineers before using any solids tracers.

Calcium Carbide Under normal circumstances the best tracer is calcium carbide which reacts with the water in the mud to form acetylene gas. This will be picked up by the mud gas detector. A fixed amount of calcium carbide is made into a small parcel using a single sheet of kitchen paper and a small amount of sticky tape to hold it together. The package is placed in the top of the drill string during a connection, just before the new stand or single length of pipe is stabbed in. The water in the mud reacts with the calcium carbide to evolve the acetylene gas which is circulated down the drillstring. When using oil based muds or synthetic fluids a small amount of water can be poured into the top of the drillstring to facilitate the reaction. The acetylene is automatically detected by the mud gas equipment and can be differentiated from drilled gas by the lack of associated methane. The arrival of the gas peak will indicate the total circulating time; the time taken for the mud to travel down the inside of the drillstring has to be subtracted from this value. The downtime is an accurate calculation since the exact internal diameters and section lengths of the drillstring are known. A comparison of the carbide lag with the theoretical lag can give an indication of the amount of borehole washout. Since it is only the open hole section that is eroded then the time difference represents the amount of enlargement of the open hole. The amount of mud pumped during that time enables a calculation of average hole diameter to be made. Of course, it may be that only a part of the open hole is being enlarged; the wellsite geologists and mudloggers may be able to predict the likely formations and a revised calculation of the average hole diameter of those sections may be made. If part of the open hole is significantly enlarged then the hydraulics may be no longer optimised and the drilling engineers will need to be appraised of the situation if excessive torque, drag and perhaps stuck pipe problems are to be avoided.

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Lag Time Pump Strokes Determining and using the lag in terms of pump strokes has distinct advantages over lag determined on a time basis. The counters tracking the cuttings up the hole stop automatically when the pump is stopped. Clocks continue to run, and some subtractive factor would have to be introduced. The most important advantage, however, lies in accuracy. A lag determined in terms of an interval of time is correct for only one speed of the circulating pump (that speed at which the lag determination was run), whereas the lag in pump strokes is accurate for any pump rate. Thus, changing pumps or running one pump rather than two does not interfere with the lagging process.

Incremental Lag It is important to continuously recalculate the lag between carbide checks. This is done by calculating the theoretical increase in annular volume as drilling proceeds and adding to the carbide lag. Eventually, of course, this lag will become inaccurate as some hole washout occurs, and a new carbide check should be performed. This can be done every 100ft or 30m when the annulus will have been changed by the length of hole drilled and the addition of drill pipe at the surface. Note that, once a calculation has been made the drill collars have already been accounted for and have merely changed their location. Some operators make the mistake of assuming that the drill collars have grown by 100ft or 30m; this is not the case. The importance of an accurate lag to drill returns logging dictates that all mud pumps should be monitored for pump strokes and that the logging unit be capable of displaying the individual strokes for each pump, as well as the total strokes and strokes per minute.

Multiple Carbide Peaks If more than one acetylene peak is found on running a carbide tracer test it may suggest that some of the gas is taking a short cut and thus arriving early. This could indicate that a small crack or hairline fracture is developing in the drillstring that, left to develop, could cause the pipe to break. Other indications of pipe washout would be an increase in pump strokes or a decrease in pump pressure. The drilling engineers need to be informed at the earliest opportunity so that, having confirmed the possibility of pipe washout, they can trip the string and remove the damaged joint(s). This may necessitate a wet trip in order to identify the location of the damaged joint which a is a slow process.


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Lag Time The multiple carbide peaks can allow an estimation of the depth to the washout to be calculated based upon the difference in time between the recorded peaks.

Natural Lag Indications When a drill-break occurs, (a significant increase in drilling rate), this may indicate that a different formation is being drilled. This may happen, for example, on drilling through a shale cap rock into a porous, permeable sandstone reservoir. Since changes in ROP are seen in real time the cuttings from the new formation, (and associated gas), will be seen one lag time later. careful observation at the shale shaker and interpretation of the mud gas analysis can give a very accurate “natural” lag time estimate without the need to use a carbide bomb.

Lag Time Calculation Calculation of lag time can be done in one of two ways: • Volumetric • Annular Velocity The volumetric calculation is usually preferable since the time, (and therefore the annular velocity) will vary with changes in pump output. Annular velocity will be important in hydraulics optimisation work for efficient hole cleaning. Calculation requires detailed knowledge of the wellbore geometry, (lengths and hole diameters) and drillstring displacement. First principles may be used but useful information can be found in many drilling engineering data handbooks and there are some short-cut calculation methods available using common oilfield units. The mudlogging unit software will automatically calculate downtime, lag time and be able to track events such as carbides, connection gas, trip gas, survey gas and drill break bottoms up. However mistakes can be made on data entry so confirmation calculations should be made from time to time as part of a thorough quality control procedure.

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Lag Time

Figure 1: Casing data

The Calculation Process There are many ways to make a lag time calculation; one method is to calculate the total hole volume and subtract the drillstring displacement to give the annular volume. This is related to the pump output to give the lag time.

Mud Pumps Most oilwell pumps will be single acting triplex pumps. Each pump consists of a cylindrical sample chamber of a specific length, the stroke, but with a variable inside diameter, the liner size. Smaller liners are used in smaller hole sizes to maintain pump pressure with reduced flowrates. Single acting triplex pumps draw mud into the chamber and then send it to the flowline; a forward and backward movement (x1 cycle or x1 pump stroke), of the pump piston therefore producing x1 volume of one sample


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Lag Time chamber. Since there are three sample chambers acting in parallel, the total volume of mud produced per stroke is x3 volume of a single chamber.

Figure 2: Mud Pump The mudlogging unit will have a sensor mounted on the pump to count strokes per minute (spm). The sensor needs to be installed correctly so that it doesn’t double count, otherwise the lag time will be incorrect. Data for the stroke length and liner size are available from the drilling crew or for data handbooks. Typically the stroke length for a triplex pump will be 11”-12”; the liner size will be from 5”-7”. Using this data the pump output in gallons, barrels or litres per stroke can be determined. A volumetric efficiency value (typically 95%) also needs to be factored. From time to time the rig crew may actually measure the amount of mud discharged from the pumps. Close attention has to be paid to the pumps since the liners will, periodically, be changed, perhaps at casing points, which will affect the discharge volume, and hence the lag time.

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Lag Time

Figure 3: Pump Output Figures A pulsation dampener, attached to the pump, smooths out the flow and regulates the pressure, by means of high pressure nitrogen and a diaphragm.

Hole Volume Estimates of hole volume can be made using: • First principles • Engineering Data Handbooks • Mathematical short-cuts Using common oilfield units Using Engineering Data Handbooks information for hole size capacity and drill string displacement can be obtained. The hole size capacities need to be internal diameters; the correct casing has to be identified from O.D. and weight per foot information. For the drill string displacement the O. D. of the pipe or collar will be required. In the case of drill pipe an allowance for tool joints has to be made. Some handbook data include tool joints in their displacement and capacity tables and others do not. The mudlogging unit software will include this information.


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Lag Time Mathematical short-cuts using common oilfield units are useful for manual calculations, particularly when checking software results. The following short-cut can be used to calculate the volume of a cylinder using oilfield units, (where d2 = cylinder or pipe diameter in inches): bbls/ft

2

= d × 0.000971 2

d 1029.4

bbls/ft = ----------------

Drilling Engineering Course Rig Maths Examples Lag Time OD"

ID"

Hole Volume Riser Casing

9.625

Open Hole

Length ft

Volume bbls

16

450

111.86

8.681

10825

792.11

8.5

1849

129.72

Total Hole Volume

Drill String Displacement Drill Pipe

5

4.276

12524

304.02

Collars

6

3

600

20.97

Total Drillstring Displacement

324.99

Annular Volume

708.69

Oump Output

Lag Time

2-8

1033.69

spm 100

bbl/stroke 0.12

gal/min 504

bbl/min 12 5906 strokes 59.06 minutes


Lag Time


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Lag Time

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Mud logging Equipment & Sensors Unit Construction The mudlogging unit is normally a purpose built Zone 1 certified steel cabin, 8-9 metres long and 2-3 metres wide. Occasionally on large production platforms the unit may be built into the infrastructure of the rig with the data engineer and computer system located with the driller, directional driller and MWD personnel. The units are air conditioned and pressurised to minimise the chance of gas entering the interior. An alarm linked to an emergency shut-down system will shut off all unit power in the event of gas invasion. The unit needs to provide adequate work-space for the data engineer, mudlogger and sample catcher, and wellsite geologist and, in some situations MWD personnel and equipment in order to serve as an office, laboratory and data acquisition centre.

Figure 1: Baker Hughes INTEQ Mudlogging Unit


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Mud logging Equipment & Sensors

Figure 2: International Logging Interior The equipment is stored in racks within the unit and linked to a computerised data acquisition system. Data from sensors, computed values and 3rd party clients is imported into the system for storage, editing and data distribution via the computer network and hard copy logs, prints and reports. Raw data is fed to chart recorders to provide a record of unadulterated information which is particularly useful in the event of an incident such as a kick occurring.

Sensors Sensors are provided to monitor drilling parameters, mud and circulation information and gas data. These are situated on the rig floor, in the pump room, shaker house and at other locations. They include:

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Mud logging Equipment & Sensors Drilling Equipment Sensors • Block Height: (Depth, ROP) Independent sensors may be mounted on the: Drawworks drum Crown block Swivel • Pump Pressure • Casing Pressure • Choke Pressure • Rotary Torque • RPM • Hookload (WOB)

Mud Sensors • Pit Volume • Mud Conductivity (in and out) • Mud Density (in and out) • Mud Temperature (in and out) • Mud Flow Out • Pump SPM

Gas Detection • Gas Trap • Vacuum System • Continuous Total Hydrocarbon Detectors • Chromatograph • H2S Detectors Ambient Sample gas stream • CO2 Detector


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Mud logging Equipment & Sensors Geological Evaluation • Binocular microscopes (variable zoom) • Fiber optic microscope light • Auto-Calcimeter • Ultra-violet light box • Sample drying oven and hood

Figure 3: Rig Sensor Locations (EXLOG)

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Mud logging Equipment & Sensors Depth and Rate of Penetration Depth increments and therefore rate of penetration are measured by monitoring the movement of the drillstring as it passes through the rig floor or rotary table. An allowance for rig heave has to be made on floating vessels. Sensors may be attached to the swivel, the crown block or directly to the drawworks drum.

Drawworks Drum The sensor fits directly onto the drawworks drum and relates rotation of the drum to vertical movement of the drillstring. A proximity sensor records the drum rotation and sends the information to the mudlogging unit. This type of sensor is easy to install, accessible and requires little maintenance or adjustment.

Figure 4: Drawworks sensor The computer software does, however, need to recognise when the wrapping of the cable around the drum passes onto a different layer as this will affect the calibration. On some floating rigs, where this sensor is installed ahead of the drillstring compensator, there can also be some operational problems.


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Mud logging Equipment & Sensors Crown Block Sensor Some mudlogging companies install a sensor on the crown block to directly measure the rotation of the sheaves and, again, relate this to vertical pipe movement. With correct calibration this provides a very accurate measurement of pipe movement since there are no additional wraps of cable around the sheaves. Floating vessels may still be a problem, however.

Figure 5: Crown Block

Swivel Mounted Sensors During the 1970s and 1980s, and in some locations still today, a hydraulic sensor mounted on the swivel also provided an indication of pipe movement. This can be traced back to the driller’s geolograph which, until fairly recently, was the main data acquisition and chart recording system for the rig crew.

Geolograph Here a wire cable was attached to the swivel, in turn fixed to a small spring loaded rotation drum. The wire cable was reeled out an in as the pipe was reciprocated and rotation of the drum related to pipe movement. The data was output on a multi-channel chart recorder mounted on a steel drum in the driller’s dog-house. The pen on the chart recorder made a mark whenever one foot of pipe movement was recorded. Whilst this gave reasonably accurate results the driller had to manually reset the pen during reaming and when moving pipe until the bit was on bottom in order not to record non-drilling episodes.

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Figure 6: Geolograph Chart


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Figure 7: Driller & Geolograph Hydraulic Sensor This type of sensor uses changes in hydraulic pressure to monitor drillstring movement. A length of rubber welder’s hose is attached to a steel bottle which is connected to the swivel. The hose is filled with water and strapped to the rubber mud inlet hose back to the standpipe and to a service box on the rig floor. The service box contains a pressure transducer to convert changes in hydraulic pressure into electrical current. The signal is fed to a chart recorder and also to the computerised data acquisition system. It was this sensor that first provided a continuous trace of pipe movement against time and that did not need to pen to be manually controlled to monitor depth and ROP changes. In cold climates the water is replaced by a water-glycol mixture to prevent freezing. This will affect the calibration and care has to be taken to use the same water-glycol concentration and to re-calibrate when the hose is refilled. An artificial atmosphere is created using a double-tube system in order to overcome excessive U-tube problems.

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Figure 8: Hydraulic Depth Sensor


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Mud logging Equipment & Sensors Heave and Tide Compensation On floating rigs allowances have to be made for heave and excessive tide variations. We want to monitor the drillstring movement with respect to the sea level or sea bed (and thus bottom-hole) and not to the rig which is moving up and down. The rig heave is measured from the riser tensioner cables as the piston rods move. This is added to or taken from the depth sensor in order to filter out rig movement.

Figure 9: Marine Riser Slip Joint

Rate of Penetration Increments to total depth are continually recorded as pipe movement is detected. The pipe tally provides calibration points for the depth when connections are made and is ultimately the definitive approximation of measured depth. Inaccuracies in pipe measurement, pipe stretch due to WOB and temperature effects and tally transcription data can result in poor estimates of measured depth.

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Mud logging Equipment & Sensors ROP can be measured over various time and depth increments, including instantaneous values. For reproduction on logs it is normally recorded as feet/hour, minutes/foot, minutes/5 feet, metres/hour or minutes/metre. Linear or logarithmic scale can be used; log plots result in fewer scale changes making the log easier to read and also emphasise changes in ROP more effectively. It is the normal API standard to record fast drilling to the left of the plot scale; this provides compatibility with gamma ray curves in sand-shale sequences to make interpretation and correlation easier.

Figure 10: Circular depth Chart


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Figure 11: Multi-channel Chart Recording

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Mud logging Equipment & Sensors Drilling Breaks Drilling breaks are sharp increases in ROP which may represent different bottomhole drilling conditions. Typically this happens when drilling through an impermeable cap rock into porous and permeable reservoir rock such as sandstone. Whether or not the new formation is significantly hydrocarbon bearing or part of the main target horizon a drilling break usually indicates at the very least a change in lithology and is important as a geological correlation tool. Reverse drilling breaks are a significant reduction in ROP such as happens when drilling out of the reservoir into shales. Drilling breaks need to be shown accurately on logs and data is recorded by the Wellsite Geologist for inclusion in morning reports. They may have associated oil and gas shows. ROP is important as a correlation tool because it is a recording of real-time changes downhole. As soon as the bits drills into a harder or softer formation the movement of the drillstring speeds up and is recorded by the depth sensor. We will have to wait for at least one lag time before the cuttings and oil or gas appear at the surface. This may be too late if we need to core the reservoir or if the lithology change indicates a casing point. Drilling breaks need to be identified as they happen, (all mudlogging sensors and data are alarmed) and the information communicated immediately to the Driller, Company Representative and Wellsite Geologist. Operational guidelines should have been issued by the Operator and Drilling Contractor to the mudloggers detailing the parameters for recognising drilling breaks and the lines of communication to be followed thereafter. Flow Check If the drilling break does represent drilling into a reservoir type rock then there is also the chance of high formation pressure being present. Where uncertainties exist, such as when drilling exploration and appraisal wells, it is usually necessary to check if it is safe to continue drilling before exposing too much of the new formation. A flow check involves ceasing drilling, stopping the pumps and waiting for at least 15 minutes for the mud to stop moving and to look for any indications of the well flowing. The pit levels are monitored together with the return flowline and bell nipple area beneath the rig floor. If the well is flowing then the BOPs can be activated, the well shut-in and safely killed. If the well is not flowing then drilling can resume. Extra care, and time, needs to be taken when using Oil Based Muds since a gas kick can flow into the mud at high bottomhole temperatures without immediately causing a pit volume or return flow increase.


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Mud logging Equipment & Sensors If the drilling break represents a target formation which is required to be cored then the Operations and Wellsite Geologists will evaluate the situation to determine whether to pull out of the hole to pick up the core barrel or not. If any uncertainties are present concerning the stratigraphy or if the log and/or drilling parameter signatures are inconclusive then a bottom hole sample may be circulated to the surface without further drilling to confirm any lithology changes or oil shows.

Figure 12: Drilling Break

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Figure 13: Mud Log - ROP Curve


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Mud logging Equipment & Sensors Drilling Engineering Sensors Standpipe (Pump) Pressure & Casing Pressure Pressure transducers are attached to the standpipe and the choke line. The Standpipe pressure gauge measures the pump pressure which is the force required to move the mud all the way around the circulating system. Sufficient pump pressure is required to have adequate bit pressure drop for hydraulics optimisation, to power downhole motors and MWD tools and to produce ECD in the annulus. Casing pressure is recorded when the well is shut induring kicks or pressure testing operations and measures the imposed pressure in the annulus. The sensors typically measure pressures from 0 - 351.5 kgf/cm² or 0-5000 psi, with accuracies of 0.1%.

Rotary Torque The sensor is designed to detect the magnetic field generated by current flowing in the DC power. The sensor is designed to detect themagnetic field generated by current flowing in the DC power cable to the rotary motor drive unit, it converts the magnetic field strength to a 4-20 mA signal. It clamps on the rotary torque power distribution cable going to drive motor, drawworks power distribution motor or the top drive unit. Torque is an indication of how much work is required to turn the drillstring and/or bit. It provides information on stalling and potential stuck pipe and twist-offs as well as providing the wellsite geologists with real-time downhole indications of changing lithologies.

RPM An RPM sensor is attached to the rotary table or top drive to measure the drillstring rotation. This necesary to monitor drilling efficiency and provides feedback, (with rotary torque), on downhole conditions. It is used by the mudloggers to normalise ROP values when performing formation pressure evaluation services. The rotary speed sensor assembly consists of a clamp-on, multi position axis device assembly. The sensor consists of a non-contacting proximity sensor element. The target is of a ferrous metal design to mount to any rotating shaft geared directly to the rotary table or top drive unit. The RPM assembly is secured by any convenient means (C-clamps, bolts), close enough to the rotating target to be activated once every turn.

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Mud logging Equipment & Sensors When a downhole motor is being used, the service company personnel will provide information on performance based upon motor configuration and pump output. This is added to the measured RPM values when used in conjunction with the rotary table or top drive.

Figure 14: BHI Mach 1 PDM Motor Specifications

Hookload The Hookload Wireline Tension Sensor is used to indicate the amount of drill string free hanging total weight and calculated bit weight of the drill string. The sensor features two fixed points at each end and one clamping point in the center of the sensor. The dead line is clamped tightly to this point, causing a slight bend in the line. With increased weight on the blocks, the dead line has a tendency to straighten. This tension force causes the sensor to provide a corresponding signal; that is, the greater the tension force on the sensor, the greater the hookload. The WOB is calculated from the difference between the maximum hookload when the bit is just off bottom and the observed hookload with WOB applied.


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Figure 15: Hook-load Sensor

Mud Sensors Pit Volume Sensors Pit level and/or pit volume is monitored for all the rig’s mud pits. The active system is particularly important since losses or gains downhole will indicate excessive permeability or the first indications of a kick. Otherwise it is necessary for inventory control and environmental impact to monitor the amount of fluid in allthe storage tanks.

Ultrasonic Sensor The probe emits a series of ultrasonic pulses from the transducer. Each pulse is reflected as an echo from the mud and sensed by the transducer. The echo is processes by proven ‘Sonic Intelligence’ techniques. Filtering is applied to help discriminate between true echoes from the mud and false echoes from acoustic and electrical noise and agitator blades in motion. The time for the pulse to travel to and from the mud is measured, temperature compensated and then converted in to distance for display and 4-20 mA output. The probe is light and easy to install by means of a 2” NPT thread or where necessary, a specially designed bracket. The intrinsically safe 4-20 mA current loop makes the wiring simple, quick and reliable. Calibration is easily performed by means of two tactile keys and a LCD display, the calibration is maintained in EEPROM which protects the data in the event of power loss. Frequent re-calibration is not necessary and only need to be checked during periodic maintenance and configured.

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Figure 16: Ultrasonic Pit Volume Sensor Float Pit Level Sensor Floats, linked to potentiometers or electronic micro-switches can measure fluid levels in mud tanks. They may be more difficult to install, less suitable on floating vessels and require more maintenance than ultra-sonic devices. Some of the rotary potentiometer based sensors with long arms may also suffer from linearity problems.

Mud Measurements Mud Conductivity Mud conductivity or resistivity measurements are used to monitor the mud for contamination from formation fluids or dissolved solids. It can give early warning of salt water kicks into a water based drilling mud, for example. Probes are placed in the mud pits and at the end of the return flowline to provide measurements of Conductivity In and Out for comparison.

Mud Density Again this is continually monitored, In and Out to check that the mud is within specification as it is circulated into the borehole and to check for contamination as it returns to the surface. Excessive solids retention can lead to increases in mud density and loss of drilling efficiency and high ECD values; gas contamination produces low effective mud density and reduced bottom hole leading to potential kicks. A differential pressure sensor consists of two pressure sensors positioned in the mud a fixed distance apart. The variation in hydrostatic pressure


3-19

Mud logging Equipment & Sensors readings over the known difference in vertical height between the sensors enables the mud density to be calculated. Gamma Ray sensors, similar to those used in wireline and MWD formation evaluation, can also be used. These sensor do, however, require nuclear source handling, storage and personnel safety issues to be addressed.

Mud Temperature Mud temperature is also continually measured, In and Out. This gives an indicatio of geothermal gradient which is useful in log interpretation, testing and formation pressure evaluation work.

Return Flow Sensor The mud flow into the borehole is calculated from the pump output data. Return flow is measured by a sensor in the flowline. Historically this information has been very difficult to obtain accurately due to sensor limitations and variations in the flow type along the return flowline. On floating rigs flow surges occur with rig heave which makes accurate measuremnts difficult. Paddles, pressure sensing devices, electromagnetic flowmeters and Coriolis effect devices are all used.

Paddles These sit in the return flowline and are either pushed through an arc by the flowing mud, connected to a potentiometer which measures the flow or just record the pressure being applied to a target.

Electromagnetic The rig flowline has to be modified since the sensor is installed in a by-pass circuit and only works in conductive drilling fluuids. The sensor consists of a pair of cicular electrodes flush with the inside of the pipe. When the sensor is energised a magnetic filed is produced at right angles to the pipe axis creating a potential difference that is proportional to the mud flow.

Coriolis Effect Again this sensor is installed on a by-pass circuit. The mud flows through tubes which twistand vibrate under the influence of fluid flow. The amount of twist in the tubes is proportional to the mass flowrate of the fluid.

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Mud logging Equipment & Sensors Pump Stroke Sensor The Pump Stroke sensor assembly consists of a clamp-on, multi position axis device assembly. The sensor consists of a non-contacting proximity sensor element. The target can be any ferrous metal component of the pump, and can either be temporarily mounted close to the pump or permanently mounted inside the main gear enclosure close enough to a rotating bolt. The Pump Stroke assembly is secured by any convenient means (C-clamps, bolts), close enough to the Pump target to be activated once every cycle.

Gas Detection Floating Gas Trap The Fixed Volume Floating Gas Trap is a robust and newly proven means of extracting well bore gases from the drilling fluid (either water or oil based). It’s design ensure a proper submerge level in the mud is continuously maintained. The Floating Gas Trap can be mounted in either the open Return Flow line or the Shaker Header box.

Application: The drilling fluid flows through the Gas-trap by means of the 70mm diameter hole in the bottom of the Gas-trap. The drilling fluid inside the trap is agitated by a reliable air driven motor mounted on top of the box section. The liberated gases are then extracted out of the box section by means of a vacuum produced by the pumps in the pneumatics assembly inside the SLS cabin. The mud inlet is automatically kept below the surface of the drill-mud. This prevents outside air or other contamination with hydrocarbons from entering the gas-trap. This simple design ensures reliability with only basic maintenance necessary, which can easily be performed by the Surface Logging crews. It’s special chamber design ensures that the gas trap floats and thus maintains it required partially submerged level in the drill mud.


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Figure 17: Floating Gas Trap

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Mud logging Equipment & Sensors QCM Gas Trap The QGM (Quantitative Measurement) gas trap was developed in a joint venture between Texaco and GRI (Gas Research Institute) in an effort to standardise different company’s gas traps and to find the best design for constant volume and linearity measurements. A cylindrical design with mud entering from below, filling up to an outlet port about halfway up with the air-gas mixture being taken off from above, all agitated with a tripod device proved to be the ideal solution.

Figure 18: QGM Gas Trap

Gas Permeable Membrane Datalog have introduced their GasWizardTM dveice which dispenses with a traditional gas trap and uses a small gas permeable membrane to detect gas in the mud. Unlike traditional traps it is not affected by positioning or variations in flow and produces very accurate estimations of gas in mud volume. It is small enough to be mounted on the bell-nipple or return flow


3-23

Mud logging Equipment & Sensors line which minimises gas losses before detection and is potentially more accurate for quantitative gas ratio analysis.

Figure 19: Datalog Gas Wizard

Vacuum System With traditional gas traps the air-gas mixture is brought to the logging unit via plastic tubing and a vacuum system. The vacuum pump and various filters and flow meters make up the system which has to be regularly and correctly maintained by the mudlogging personnel for optimum gas evaluation efficiency.

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Figure 20: Vacuum System


3-25

Mud logging Equipment & Sensors Gas Detectors Once separated from the mud and brought into the mudlogging unit the air gas mixture is analyzed for its hydrocarbon, H2S or CO2 content. The total amount of combustible hydrocarbons is recorde as Total Gas and the make up of the gas is determined from chromatographic analysis. The Total Gas reading is continuous but the chromatograph takes a certain amount of time to process a sample, during which time no new information is processed. Thus, the shorter the processing time the better the resolution. Older chromatographs may take 4-5 minutes to detect as far as Pentane; modern machines may only take 30 seconds or so.

Figure 21: Total gas & Chromatograph

3-26


Mud logging Equipment & Sensors Geological Assistance The mudlogging unit is equippped with zoom binocular microscopes, UltraViolet light box and Hydrochloric Acid for cuttings evaluation. Other specialist equipment is also available such as:

Autocalcimeter This device measures the rate of response of dilute Hydrochloric Acid on rock samples to give an indication of the total carbonate content and the relative amounts of limestone and dolomite in the sample. This is useful in complex carbonate sequences where subjectivity can be a problem. The device is calibrated with a fixed amount of 100% CaCO3 and the same weight of sample used for testing. Dilute hydrochloric Acid is added to the sample and the CO2 given off given off during the carbonate-acid reaction is measured by a pressure transducer and converted to an electrical signal. The information is output digitally to a databas and also to a chart rcorder. The first, very fast reaction indicates the amount of calcite (limestone) content and the continued, slower reaction indicates the dolomite content.

Figure 22: Auto calcimeter


3-27


Figure 23: Autocalcimeter chart

Cuttings Catcher Using a cuttings catcher machine, the system measures the raw mass of solids coming over the shaker. The system removes the calculated mass of mud additives and attached fluid to give an online value for actual formation solids being removed from the hole. Comparing this measurement to the anticipated values provides a real-time indicator of hole-cleaning, hole conditions, mud conditioning and overall drilling efficiency.

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Figure 24: Cuttings Catcher


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Gas Detection & Evaluation Gas Composition Hydrocarbon compounds consist of hydrogen and carbon atoms classified into two types depending on the molecular bonding of the carbon atoms: • Saturated (Alkanes) One single covalent bond between the carbon atoms • Unsaturated (Aromatics) Double bonds between the carbon atoms

Saturated Hydrocarbons (Alkanes) These consist of short chains of carbon atoms saturated with hydrogen atoms that occupy all available sites. Chains may be straight, branched or cyclic.

Straight and Branched Chains (Paraffins) The straight chained, normal, alkanes have the general formula:

CnH2n+2

Where n ranges from 1-10 the members are: • Methane (C1) • Ethane (C2) • Propane (C3) • Butane (C4) • Pentane (C5) • Hexane (C6) • Heptane (C7) • Octane (C8) • Nonane (C9) • Decane (C10)


4-1

Gas Detection & Evaluation

Figure 1: Hydrocarbon Structures Wellsite chromatography usually goes as far as Pentane since the heavier members will tend to retain liquid state at surface pressure and temperature. Pentane condenses to a liquid at 36ºC and so may not be a gas at very high mud temperatures.

4-2


Gas Detection & Evaluation The branched chain series begins from Butane (C4) and wellsite analysis will usually detect iso-Butane and iso-Pentane.

Closed Chains (Napthenes) In this group of alkanes the carbon atoms are arranged in a closed chain and saturated with hydrogen atoms. The normal paraffin series names are prefixed with cyclo-, and have the general formula:

CnH2n Napthenes are slightly lighter than paraffins since they have two fewer hydrogen atoms. They are usually indistinguishable from Butanes and Pentanes at the wellsite because of their similar molecular weights.

Unsaturated Hydrocarbons (Aromatics) The aromatics are closed chain structures but, unlike the alkanes, are not saturated with hydrogen. They are usually only minor constituents of most crudes but benzene is, nevertheless, quite common.

Crude Oil Classification Whilst basic density can be used to classify crude oils the API Gravity value is normally used. This is related to the density of the crude at 16ºC as follows:

141.5 API Gravity = ⎛⎝ ------------------------------- – 131.5⎞⎠ S.G. at 16°C The larger the API value the lighter the oil, thus low API gravity oils are high density. API values are estimated by the wellsite geologists and mudloggers by observing natural fluorescence under UV light and, occasionally, by using refractometers. Natural fluorescence ranges from dull brown through yellow gold and blue white to colourless as the API gravity increases. Oils at the end of the scale can be difficult to detect by visual fluorescence methods alone.


4-3

Gas Detection & Evaluation Gas Detection & Evaluation Mud logging is performed by using the returning mudstream as a medium of communication with the bottom of the hole (bottomhole). There is a relationship between the kind and amount of gas or oil (or both) in the drilling mud arriving at the surface, and the gas and oil (or both) that was in place in the formation being drilled at the time that portion of mud was passing bottomhole. The gases, if present, are released by the cuttings into the mudstream and entrained, probably in solution, in the drilling mud. It remains, then, to remove and detect this parameter from the mudstream. To do this, the following equipment is used:

The Gas Trap To meet the unique requirements of mud logging, this device must perform important functions: • Extract the gas contained in the drilling mud, independent of such variables as density, viscosity, and gel strength of the mud • Sample consistently, regardless of the flowrate of mud through the circulating system The gas trap is a steel container that sits in the mud ditch (as near to the flowline exit as possible, but before the shakers) and allows the drilling fluid to continuously pass through it by means of slots in the base. An agitator motor sits on top of the gas trap and has a propeller shaft extending into it. The propeller continually agitates the drilling fluid as it passes through the trap. A continuous flow of air enters through a vent in the top of the trap and is whipped through the mud where the maximum mud surface is exposed. It is this air-gas mixture that is subsequently drawn into the gas detector.

The Vacuum System After the gases are removed from the mud, they are transported to the gas detector in the logging unit. This is accomplished by a vacuum pump which is connected to the trap by a length of hose. Through this hose the pump pulls a continuous measured stream of fresh air through the vent in the trap. Because the gases, if present, are being continuously extracted from the mud in the trap, they are mixed with this stream of air and carried into the logging unit via a condensate bottle, where water vapour is extracted. The flow of air, or air-gas mixture, passes through additional flow-regulation equipment, plumbing, and instruments and arrives at the detector where a continuous gas reading is obtained.

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Figure 2: Basic Gas Trap

Figure 3: QGM Gas TRap


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Figure 4: Vacuum System

The Gas Detection System Catalytic (Hotwire) Gas Detector This instrument functions on the principle of catalysis, i.e., the catalytic oxidation of gases on a filament in the presence of air. It is an application of the Wheatstone bridge measuring circuit in which a resistance (the detector filament), which varies according to the concentration of gas, is balanced against a fixed standard (the reference filament). The reference filament is coated with an inert compound to seal the catalytic surface from the atmosphere, and the imbalance is measured. With the normal voltage applied across the entire bridge, both filaments are heated sufficiently to oxidise all gaseous hydrocarbons. Before the gas detector is placed in operation, it is calibrated using air as a standard. A valve (zero adjust) is opened to admit fresh air to the system,

4-6



Figure 5: Catalytic Detector which places both filaments in a like atmosphere in which the gas concentration is zero. By adjusting the zero potentiometer, the gas meter, which is a sensitive milliammeter, is adjusted to read zero. Electrically, the gas detector is then said to be in balance. The zero adjust valve is then closed, and the filaments will be in whatever atmosphere is being created in the trap. As long as no gas is being liberated from the mud, the filaments remain in an atmosphere of air and the detector reads zero units of gas. However, as soon as any gas from the mud becomes mixed with the air being drawn through the detector, the filaments are surrounded by this atmosphere. Having free access to the detector filament, this mixture oxidises. The oxidation creates heat; the detector filament temperature is increased (increasing resistance); the electrical balance is upset; and current flows through the milliammeter.


4-7

Gas Detection & Evaluation The greater the gas content present, the greater the electrical imbalance and the resultant gas reading will increase. To quantify the gas reading, a known concentration of combustible gas, usually methane at 1% by volume in air is passed over the filament and the gas reading is adjusted to reflect the concentration. Older style gas detectors may display gas concentration in “units” and various mud logging companies use different definition of what concentrates a “unit”. Traditionally, API has used 50 units equals 1% with catalytic gas detector and each log heading explains what calibration has been used.Because of the varying values of the term unit, it is common to report gas readings on the Mud Log in terms of percent-methane-in-air, or parts per million, as well as in units, in order that well to well comparisons can be made of gas readings.In the catalytic system, if the gas concentration becomes greater than 2 percent, the mixture must be diluted so that the readings will be on-scale. This is accomplished by introducing air from the atmosphere into the air-gas mixture and is controlled volumetrically by air flowmeters. When the volume of air-gas mixture is reduced by one-half, the scale of the milliammeter (and the recorder) is effectively doubled and the gas reading shown must be multiplied by two.

Flame Ionisation Gas Detector (FID) With this system a continuous sample is fed into a regulated, constant-temperature hydrogen flame. The flame is situated in a high-potential (300 volts) atmosphere between two electrodes. As combustion occurs, the gas ionises into charged hydrocarbon resides and free electrons. A predictably constant ratio of these charged particles moves immediately to the positive electrode, inducing a current at that probe. The amount of current induced is proportional to the total ion charge produced in the flame and increases as the percentage of hydrocarbons in the sample increases. The ion charge becomes essentially a measure of the total number of carbon to hydrogen bonds present in the air-gas mixture. The FID detector meter displays the percentage of methane-equivalent (C1) hydrocarbons present in the ditch sample. It is calibrated to read 1.00 when a 1% methane calibration gas burns in the FID. When burning a ditch sample containing heavier petroleum vapours (those with a greater number of carbon-hydrogen bonds in the molecular structure than in methane), the meter displays a reading reflecting the proportionately greater number of carbon-hydrogen bonds. For example, when burning a 1% concentration of pentane (C5), the meter reads 5.00; when burning a 2% pentane or a 10% methane mixture, the meter reads 10.00 (2% pentane = 2 x 5 =10 carbon-hydrogen bonds; 10% methane = 10 x 1 = 10 carbon-hydrogen bonds. Each of these readings indi-

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Gas Detection & Evaluation cates that the relative concentration of combustible hydrocarbons is 10 times greater than that in the calibration gas.

Figure 6: FID Detector

Cuttings Gas Analyser The blender gas analyser is used to check the combustible hydrocarbon content of the drilling mud and cuttings. It differs from the ditch gas analyser in that it is a batch system. Samples of the drilling fluid and cuttings are collected and checked periodically - and always during any ditch gas shows. These samples (approximately 100 cm, but always a consistent amount) are placed in the blender jar and agitated for a standard length of time, and the resultant air-gas mixture is drawn through the catalytic gas detector. The gas combustion, air dilution, milliammeters, voltmeters and flowmeters are all identical to (and are employed in the same manner as) those in the ditch gas analyser. But as this is a batch system, no recorder is used and the gas readings are read directly from the milliammeters as gas readings. On prospective gas wells the blender gas results are used mainly as a check on the ditch gas analysing system. On prospective oil wells and wildcat wells, the cuttings gas is extremely important as it may form the basis for


4-9

Gas Detection & Evaluation further evaluation as an indicator of reservoir porosity and permeability, or of source rock.

Figure 7: Cuttings Gas Detector

Chromatography The chromatograph separates and analyses hydrocarbons in the ditch gas sample to determine how much of each hydrocarbon is contained in the sample. There are two common types of chromatograph: the catalytic detector, and the flame ionisation detector (FID). Each separates and records the gases in a similar manner, but the difference between the two is the way in which the various gases are detected once separation has occurred.

Catalytic Chromatograph The catalytic chromatograph separates the hydrocarbons by passing the sample through a tube containing a compound of hexadecane and firebrick. The compound is housed in coiled aluminium columns, and a predetermined quantity of the sample is cycled through the columns at 5-minute intervals. The principle of chromatography is that, when forced through a certain medium, different compounds move at different rates depending on their molecular weight. Lighter hydrocarbons pass through the columns first, followed by the heavier molecules. The order in which these hydrocarbons arrive at the

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Gas Detection & Evaluation detector are: methane (C1), ethane (C2), propane (C3), isobutane, (iC4), and normal butane (C4). The columns are held at a constant temperature between 100 to 150 degrees F inside the oven to ensure a constant flowrate through the columns. The hydrocarbons flowing to the filament block catalyse on the active filament.

Figure 8: Chromatograph Schematic When the hydrocarbon to be tested enters the chamber, the carrier air and the hydrocarbon combine on the filament. The filament remains unchanged, but the catalysis causes the filament to heat in proportion to the hydrocarbon concentration in the sample. The active filament is an integral part of a balanced resistance (Wheatstone) bridge which has a normal output of 0 volts. When catalysis occurs, both the current through, and resistance of, the filament change, and the output of the bridge varies. The output of the bridge then goes to the recorder.If higher than butanes analyses are required (e.g. pentanes (C5)), the chromatograph can be set to HOLD and


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Gas Detection & Evaluation the cycle is extended beyond the normal 5 minutes. There are a few disadvantages to the catalytic chromatograph:

• The theoretical upper limit of sensitivity of the hot-wire filament for methane is 9.5%. At higher concentrations, reversals occur due to insufficient oxygen being available for complete combustion, and the excess methane cools the filament. • It has a negative response to carbon dioxide. • It is affected by large amounts of nitrogen and suffers thermal drift due to temperature changes.

FID Chromatograph Once separation has occurred, the individual hydrocarbons go to a circular chamber inside an aluminium block for detection. This chamber (the FID chamber) completely encloses a hydrogen flame which is not affected by logging unit pressure or by normal amounts of carbon dioxide and nitrogen.The hydrocarbons are mixed with the hydrogen flow and heated in the chamber. The detector response is essentially proportional to the carbon content of a molecule and depends upon the quantity of gas entering the flame per unit of time. Mixing hydrocarbons with the hydrogen flame produces ions which are attracted to a probe in the FID chamber. The ions then flow to a high-gain amplifier, then to a chart recorder and digital meter. The FID has a greater dynamic range and has a wider linear range than the catalytic chromatograph. It is also less likely to be affected by temperature change.

The Chromatogram The chart recording of the gas-air mixture is termed a chromatogram. The sensitivity of the detector to each gas is established on a regular basis by passing a calibrated sample through the column. This calibration mixture contains known concentrations of methane through pentane.

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Figure 9: Chromatogram

Gas Show Evaluation Origin of Gas Shows A gas show can be defined as a significant occurrence of hydrocarbon gases detected from the mudstream and identifiable as being the result of the drilling of a specific increment of formation.The object of good mud logging is to plot those gas readings produced by gases liberated from cut formation in conjunction with those data relevant to their interpretation. The object is to reconstruct from these data the composition and mobility of reservoir hydrocarbons. In order to reconstruct a picture of the fluids in place in a formation and the type of fluid the formation may produce, it is necessary to study gas magnitude and composition in the mudstream and cuttings, geological and physical character of the cuttings themselves, and changes in the


4-13

Gas Detection & Evaluation drilling process and circulation system which may affect or be affected by formation fluid behaviour. Prior to examining the factors affecting gas shows, some definitions are in order:

True Zero Gas

Figure 10: Total Gas Chart Recording

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Gas Detection & Evaluation This is the value seen by the gas detector when pure air is passed across the detecting element. Some gas is seen by a gas detector when circulating with the bit off-bottom and with no vertical movement. Under such normal conditions, meaning a clean, balanced borehole, some gas will be present in the sample drawn from the mudstream, but it will represent only contamination or recycled hydrocarbons in the mud. This value is taken as the baseline above which all gas readings are taken for drafting on the mudlog. The background zero will vary continually with additions to the mud system, and with mud and ambient temperature. The value must be regularly re-established to allow accurate, consistent gas logging.

Background Gas When drilling through a consistent lithology, it is common for a consistent gas value to be recorded. Certain lithologies (for example, overpressured shales) may show considerable rapid variation in Background Gas but usually with some consistent average value.

Gas Show This is any deviation in gas, amount or composition, from the established background. This may or may not accompany a change in lithology, may or may not be as a result of the drilling process, may or may not indicate a significant or economic hydrocarbon accumulation. It is the responsibility of the Logging Geologist to interpret the gas show to determine it’s cause and significance.

Types of Gas Show “What is a good gas show?” is a common question asked of the logger. The answer to this is complex and relates to many factors beyond the simple number of gas units seen. To decide whether a gas show is good or poor, i.e. whether or not a significant hydrocarbon accumulation is indicated, requires a total evaluation of all mud log parameters plus consideration of the many variable system conditions.

Sources of Gas in Mud Gas detected in the mud stream may originate from the formation via a number of mechanisms. It is necessary for the geologist to isolate and attribute these causes in order to draw the appropriate conclusions. Gas originating from other sources or only indirectly from the formation will also be seen in the mudstream. This must, if possible, be recognised and removed from consideration.Drilled Gas This is often referred to as liberated gas since it is liberated into the mudstream from the crushed cylinder of formation produced by the drilling process.


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Gas Detection & Evaluation Post-drilling Gas Sometimes referred to as produced gas, since it is gas which has flowed from the formation into the borehole in the same manner as if the formation were to be produced. Post-drilling gas, i.e. gas entering the borehole from the borehole wall or bottom when drilling is not taking place, is of two distinct types:

Figure 11: Sources of Gas Swabbing When pipe is pulled from the hole, or circulation halted, a condition of underbalance may exist at some point in the borehole. The differential pressure to the advantage of the formation will cause fluid to flow into the borehole from the formation.

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Gas Detection & Evaluation Filtration In a condition of balance or even with some overbalance there will be a continual diffusion of fluids between the formation and the borehole. This will be encouraged by removal of filter cake by pipe movement and by the flow of drilling fluid past the exposed borehole wall.

Recycled Gas Not all of the gas entrained in the mudstream will be liberated at the gas trap. If insufficient degassing takes place in the surface mud system, drilling fluid containing gas may be pumped back into the borehole. Travel of the light gas-cut mud past gas-bearing formations in the borehole may encourage diffusion of more gas into the mud.

Contaminants Gas resulting from the addition of petroleum products to the drilling fluid or from the degradation of normally inert mud additives may result in anomalous gas shows. Similar anomalies may result from the presence in the circulating system of crude oil from previously drilled or tested formations

Factors Affecting Gas Shows Although the crushed cylinder of formation produced by drilling releases a quantity of gas which may be detected at the surface, this gas undergoes many influences between the formation and the gas detector.

Downhole Influences Flushing It is well known that where borehole pressure exceeds formation pressure, and permeability exists, the drilling fluid will tend to flush into the formation. If the solids diameter is sufficiently high, filtration will result. Such flushing commonly causes little formation damage since invasion takes place only a short distance into the formation. However, where effective porosity is low, only a small volume of flushing may give a large diameter of invasion. Displacement of gas some distance from the borehole in this way may reduce the reservoir’s gas saturation and effective permeability to gas close to zero in the vicinity of the borehole. Thus a zone which gives good gas shows when drilled will appear water-bearing or recover only mud filtrate when logged or tested. Flushing will also take place at the bottom of the hole when an overbalance exists. In this circumstance no permanent mud filter cake can be formed due to the continuous action of the bit. Flushing below the drill bit will have most effect when the reservoir has high permeability and effective porosity. The differential pressure to the advantage of the borehole combined with high


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Gas Detection & Evaluation impact force due to the jet nozzle pressure drop will force mud filtrate into the formation ahead of the bit.

Figure 12: Flushing When the formation is eventually drilled, little or no gas will be liberated. At the surface, a flat unresponsive gas curve will be seen which may even indicate less gas than in nearby lithologies. Since permeability is high, the reservoir will return to it’s natural state soon after drilling, and an apparently water-bearing reservoir will later be logged or tested as productive.

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Gas Detection & Evaluation Common good drilling practice in minimising mudweight and water loss will be advantageous in reducing flushing. On the Mud Log, the following information should be recorded for proper interpretation of possible flushing: • Pump Pressure • Jet Nozzle Sizes • Mud Rheology/Mud Weight & ECD • Estimate of Pore Pressure • Water Loss • Lithology Description including visual porosity. A formation indicating high porosity and permeability confirmed by a good rate of penetration, which shows little or no gas in either mud or cuttings, should be strongly suspected of being flushed prior to drilling - especially where an overbalance exists. However, the possibility does exist that the formation contains only water without even gas in solution. This possibility may be confirmed or rejected by monitoring mud salinity. Fluid Incursion The incursion of fluid into the borehole may result from a number of causes, some but not all of which result from an underbalanced condition of either a temporary or permanent nature. Where an underbalanced condition exists, there is a natural tendency for fluid to flow from the formation into the borehole. Where a formation exists having good porosity and permeability, this flow may be massive and a kick could occur. Where an underbalance sufficient to cause a kick exists but there is insufficient permeability to sustain a massive fluid influx, a steady fluid feed-in may result. If this minor flow is from discrete formation already cut, it will be noticeable- producing a sustained minimum gas background even when circulating, but not drilling. If the feed-in is from the formation currently being drilled, then as a greater and greater area of formation in the borehole wall is exposed by drilling, increasing flow will take place. If this is the case, the mud gas will exhibit a sustained minimum when circulating but will consistently rise as drilling proceeds. Cuttings gas will inevitably be high relative to mud gas since is only lack of permeability which is preventing the feed-in from becoming a kick. When permeability i.e. effectively absent, e.g. in clays and shales, even minor feed-in cannot take place. Fluid pressure in the rock will gain access to the borehole by the opening of pre-existing microfractures and partings in


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Gas Detection & Evaluation the rock. The result will be the caving or sloughing of rock fragments into the borehole, accompanied by a small amount of gas. As above, a minimum gas background and, in this case, cavings recovery will exist even when circulating without drilling.

Figure 13: Connection Gas

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Gas Detection & Evaluation At connections and trips, the reduction in bottom hole pressure may cause there to be a temporary underbalance condition. Downtime gas or connection gas is a gas show resulting from this momentary underbalance due to pump shutdown and/or pipe movement. It can be recognised by the occurrence of discrete gas show appearance at, or slightly less than, the lag time after circulation recommences.Fluid incursion into the borehole may also occur when there is a balanced or even slightly overbalanced condition. This situation is associated with the flushing effect already mentioned. Where a sufficient thickness of formation has been cut and vertical permeability exists, it is possible for these displaced formation fluids to be displaced back into the borehole at some point above bit turbulence. The effect of this during normal drilling will be to effectively delay the appearance of a gas show until some time after the formation is cut. Such a mechanism is termed sweeping.

Figure 14: Kelly Cut Gas


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Gas Detection & Evaluation Formation Porosity and Saturation The amount of gas released to the mudstream from a specific interval of formation will depend on: • Total Porosity • Effective Porosity • Effective Permeability • Gas Saturation • Drill Rate Assuming that all other formation, mud and drilling considerations are held constant, the amount of gas liberated to the mudstream by drilling will be a function of the total volume of effective porosity exposed to the mudstream by the cutting action of the bit. This will be dependent upon the volume of the cylinder of formation cut. It will also vary with bit selection since different bits provide different sizes of cuttings.A formation identical in all ways will produce higher mud gas readings if drilled at a higher rate of penetration. Bit Size and Type The second factor controlling the volume of the cylinder of formation cut is the hole diameter. Also the size of the teeth on the bit, which is governed by both bit type and size, will control the size of cuttings produced. Where cuttings are smaller and more numerous, formation fluids will be more easily liberated from non-effective porosity and inferior permeability, giving improved gas shows. Flow Rate The volume of gas or cuttings entering any volume of mud passing bottom will be a function of mud flowrate. Since mud logging gas analysis depends upon the analysis of gas extracted from the mud, changes in flowrate will affect the apparent gas show magnitude. As mud flowrate increases, the volume of gas and cuttings contained in a fixed volume of mud will decrease. Conversely, the volume of mud passing through the gas trap will increase. The net effect should be zero. In fact, the complex geometries and variable efficiencies of the various parts of the system will introduce some variations, but the overall effect is probably not great. Furthermore, mud flow rate will not vary greatly within any hole size or in relation to hole size within hole sections. This further removes the severity of this effect.

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Figure 15: Bit Size Borehole Contamination A common source of gas contamination is the degradation of organic-based mud additives, e.g. lignosulphonate dispersant. These will degrade due to the effect of heat and with the catalytic support of the clay ion exchange sites on the mineral matrix. The common product of degradation is methane, although more complex hydrocarbons may also be present. The second major cause of contamination is the addition of small amounts of crude or diesel oil to the mud as a lubricant. Crude oil may be a serious problem since it will mask later oil or gas shows. The more commonly used diesel oil is much less of a problem since the gases liberated from it and it’s appearance in samples are atypical for a natural crude oil.The gas content, due to contamination of the mud, will continually vary. As oil additions are made and recycles occur, peaks will develop in the system. It is important that the logging geologist regularly re-establish the background zero above which gas shows are read.


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Gas Detection & Evaluation Surface Influences Although there are many factors which can affect the liberation and transport of gas to the surface, it is readily observed that the most important factors controlling the final magnitude of a gas show are the rig’s surface system and the extraction, pneumatic, and detection systems of the mud logging unit. Flowline It is well known that a high degree of degassing takes place in the conductor and flowline. Loss of gas in the flowline will be especially important where: • Flowline is not filled with mud • Changes in slope promote turbulence • Sections of the flowline are open to the atmosphere • Flowline enters the possum belly above the mud level. Geometry of the ditch will be of considerable effect in the volume of mud and gas available to the gas trap. Location of flowline entry, direction of major flow and degree of turbulence will all affect the efficiency of the gas collection system.

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Figure 16: Rate of Penetration Gas Trap The efficiency of the gas trap can vary between 30% and 70% depending upon design, location and mud properties, but most importantly upon careful maintenance and good operation. The trap and it’s immediate surroundings should be kept clear of cuttings debris, settled debris, or mud caking, all of which may restrict or modify the flow of mud and air through the trap.


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Gas Detection & Evaluation Mechanical efficiency of the trap is controlled by the rotational speed and surface blade area of the trap impeller, strength of vacuum and flowrate of air from the trap. Even when installation and maintenance of the gas extraction system ensures maximum mechanical efficiency, there will be variations in the overall efficiency of the extraction and the magnitude of gas shows. This will depend on the composition of gas present, distribution of gas in the mud, viscosity and gel strength of the mud, and flowrate.

Summary the magnitude of gas shows recorded on the logging unit’s gas detection system and their interpretation will depend on numerous factors, including: • Formation characteristics - porosity, permeability, saturations • Flushing effects - controlled by overbalance, mud water loss, formation porosity/permeability • Volume of formation cut - controlled by drill rate, bit diameter • Size and nature of cuttings - controlled by bit design • Flowrate - to a small degree • Produced, recycled and contamination gas in mud • Loss of mud at surface - flowline, ditch characteristics • Gas Trap Efficiency • Vacuum System • Gas Detection Equipment efficiency and calibration. In order to account for a number of variables so that gas readings can be better compared between wells, Gas Normalisation techniques can be employed.

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Gas Detection & Evaluation Gas Ratio Analysis Gas ratio techniques are based on the theory that an increasing hydrocarbon fluid density in the reservoir will manifest itself at the surface as an increasing gas density. Thus, while a quantitative analysis of surface gas to reservoir fluid is not possible, a qualitative analysis is possible.The most common method used today was developed by Baker Hughes INTEQ, and comprises: • Gas Wetness Ratio • Light-Heavy Ratio • Oil Character Qualifier

Gas Wetness Ratio (GWR, Wh) C2 + C3 + C4 + C5 ------------------------------------------------------------× 100 C1 + C2 + C3 + C4 + C5

Note: The ratio is multiplied by 100 only to obtain a percentage; thus it can be plotted alongside other ratios (e.g. LHR). The Gas Wetness ratio has been extensively used in the past, especially for geochemical soil sampling.The GWR value increases with increasing fluid density, and setpoints have been established as follows:

Gas Wetness Ratio

Fluid Character

0.5

Very dry gas

0.5 - 17.5

Gas, increasing density

17.5 - 40

Oil, increasing density

>40

Residual oil

Figure 17: Hydrocarbon Types from Wetness Ratio


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Gas Detection & Evaluation Light-Heavy Ratio (LHR, Bh) C1 + C2 ---------------------------------C3 + C4 + C5 This ratio has an inverse relationship with the GWR, and decreases with increasing fluid density. Methane and ethane are included in the numerator to place the two primary coal gases together. This removes the coal-bed effects that could cause anomalies in the GWR ratio. The relationship of the GWR and LHR curves gives a visual interpretation of the fluid nature as follows:

• If LHR is greater than 100, the zone is excessively dry gas (probably unproductive). • If GWR is in the gas phase and LHR is greater than GWR, then as the curves get closer, the gas gets denser. • If GWR is in the gas phase and LHR is less than GWR, then gas/oil or gas/ condensate is indicated. • If GWR is in the oil phase and LHR is less than GWR, then the greater the separation, the greater the density of oil. • If GWR is in the residual oil phase (GWR 40) and LHR is less than GWR, then residual oil is indicated.

Oil Character Qualifier (OCQ, Ch) C4 + nC4 + C5 -------------------------------------C3

i

Anomalies caused by methane occur if there is low permeability, water, a gas cap, or dual gas/oil production with a higher gas-to-oil ratio. These anomalies cause a dampening effect on the movement of the GWR and LHR curves, impeding the interpretation of fluid density. The OCQ ratio was chosen to offset this anomaly. The relative increase in methane that occurs in these situations accompanies a relative increase in C4 rather than C3. Although not fully studied, this occurrence probably represents the increasing iC4 rather than the nC4 isomer. After the GWR and LHR curves are compared, the OCQ curve must be checked. If OCQ is less than 0.5, gas potential is indicated and GWR versus LHR interpretation is correct. If OCQ is greater than 0.5, gas associated with oil is indicated.

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Figure 18: Gas Ratios and Fluid Tying


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Figure 19: Gas Ratio Log

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Gas Detection & Evaluation Gas Normalisation Absolute quantification of a gas show is not possible in mud logging; there are too many in situ and drilling variables to calculate during the initial evaluation. The in situ variables include porosity, relative permeability, gas saturation, temperature, pressure, solubility, and compressibility of the gases. Once the formation has been penetrated by the drill bit, other variables come into effect - flushed saturation, rate of penetration, pump rate, hole size, rock and gas volume, differential pressure and temperature, phase changes, and surface losses. Normalisation is a mathematical treatment of parameters that affect gas shows. Although attempts have been made to cover downhole effects such as saturation, temperature, pressure etc., normalisation do not try to cover surface losses caused by the variations in flowline and ditch geometries and gas trap efficiencies. The most common form of normalisation involves correction for drill rate, hole size, and pump (flow) rate. Since these three parameters are continuously monitored while drilling, their values can be used immediately in normalisation calculations.Ideally, there should be a universal set of standard parameters for hole size, drill rate and flow rate. In reality, however, an ideal situation in one area may not be ideal in another. Another problem is the quantitative use of carbide data. Some authorities like to normalise for the carbide gas peak. Sometimes, though, this can introduce more variables than the quantity it corrects. The basic normalisation formula which corrects for drill rate, hole diameter, and flowrate is:

Dn 2 G d × ROP n × π ⎛ ------⎞ × Q o × 1 ⎝ 2⎠ G n = -------------------------------------------------------------------------2 D o ROP o × π ⎛ ------⎞ × Q n × E ⎝ 2⎠ Where: ROPo =

observed drill rate (ft/hr)

Qn =

normalised flow rate (gpm)

Qo =

observed flow rate (gpm)

dn =

normalised hole diameter (inches)


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Gas Detection & Evaluation do =

observed hole diameter (inches)

Gd =

ditch gas reading (units)

Gn =

normalised ditch gas (units)

E=

Gas Trap Efficiency

This formula represents an approach to gas normalisation. There may be other factors that can be included such as mud density or ECD and pore pressure which may make the normalisation more useful.

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Sedimentary Petrology Classification of Sedimentary Rocks Grain Size Parameters The basic descriptive tool for all sedimentary rocks is grain size. The most widely used is the Udden-Wentworth scale which divides sediments into seven grades: • Clay • Silt • Sand • Granules • Pebbles • Cobbles • Boulders Furthermore the silts and sands are sub-divided into intermediate classes. The full scale is shown below. These sedimentary rocks are also referred to by descriptive names, also based on grainsize, for example: • Clays:

Argillaceous

• Sands:

Arenaceous

• Pebbles etc.:

Rudaceous

At the wellsite, grain size is determined by visual inspection and estimated accordingly. There are several methods for accurate determination in the laboratory, but these are not applicable for wellsite use due to time and equipment limitations, although some software is becoming available to help. Within the major grain size based classifications listed above there is a need for more detailed notation in order to address variations in content (rock fragments and mineralogy) and environments of deposition.


5-1

Sedimentary Petrology

mm

Clastic Sediments

Rock Names

Gravel

Boulder 256.00 Cobble 64.00

Other Names

Rudite Conglomerates

Pebble

Rudaceous Sediments

Granule

Breccias

4.00 2.00 Very Coarse Sand 1.00

Sandstone

Coarse Sand 0.50 Medium Sand 0.25

Arenaceous Sediments Sandstones Arkose

Fine Sand 0.125 Very Fine Sand 0.0625 Coarse Silt 0.031 Medium Silt 0.016

Siltstone Siltstones

Fine Silt 0.008 Very Fine Silt 0.004 Clay

Mudstone Claystones Shale

Figure 1: Udden-Wentworth Grain Size Scale

Classification of Sandstones The classification produced by Pettijohn splits sandstones according to the proportion of grains to matrix and also by content of the relative amounts of Quartz, Feldspar and Rock fragments.

5-2


Sedimentary Petrology Quartz Arenites These represent sandstones with at least 95% quartz grains and are therefore the most mature sandstones. Frequently they are also well rounded and well sorted.

Arkoses These are sandstones containing more than 25% feldspar, with the rest being quartz grains and rock fragments. They are typically red or pink because of the feldspar colour, and also due to iron staining. They are derived from granite and gneiss and typically are deposited close to the source. Texture is typically poorly sorted with angular to sub rounded grains. They are often indicative of arid conditions since moisture will promote the weathering and destruction of feldspar.

Litharenites These are composed mainly of rock fragments. cements are usually calcite or quartz. They indicate fairly rapid deposition and short transport distances.

Greywackes Characteristically they are composed of quartz grains held by a fine grained matrix. Many rock fragments are also usually present. They are often dark coloured, even black rocks, sometimes resembling dolerite. Many greywackes were deposited by turbidity currents on continental shelves, often associated with volcanic activity.

Classification of Mudrocks These are the most abundant of all sedimentary rocks, constituting almost half of all sedimentary sequences. Major depositional sites are floodplains, lagoons, lakes, deltas and ocean floors. The main constituents are clay minerals and silt sized quartz. According to grain size, clay is less than 4mm in diameter, though by mineralogy it is a hydrated aluminium silicate with a specific sheet structure. Terminology applied to mudrocks can be confusing, and in the oil industry is largely controlled by the specific operator and the system of classification that they have adopted.

Claystone This is a general term describing fine grain rocks composed mainly of clay minerals.


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Sedimentary Petrology Mudstone Synonymous with claystone but can be confusing if the Dunham classification of carbonates is being used since there is a limestone also referred to as mudstone.

Siltstone An argillaceous rock composed mostly of silt sized particles, between 4 and 62 mm.

Shale This is a much abused term at the wellsite, being used by most “non-geologists” to describe any mudrock. The term shale has a specific meaning however, and refers to a mudrock that, because of composition, compaction and burial, shows lamination and fissility. It should not be used as a generic descriptive term for all mudrocks.

Classification of Limestones There are many classification schemes for limestones, but all differ significantly from those adopted for clastic sediments. Most limestones are formed in situ and thus textural features, based on grain size and shape as a result of erosion, transportation and deposition, do not really apply. The important features are the nature and type of component grains and the cement or matrix which holds them together. The most commonly used classification scheme in the oil industry is the Dunham Classification. This splits limestones according to the amount of granular material, whether or not it is self supporting, and the type of matrix or cement holding it together. These features provide an indication of environment and energy levels present at formation. The descriptive terms used are:

Mudstone Rocks composed mainly of fine grained carbonate mud with less than 10% grains.

Wackestone Predominately mud supported grains,, which comprise more than 10% of the total volume.

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Figure 2: Dunham Classification (Limestones)

Packestone Grain supported limestones held by a fine grained carbonate mud matrix.

Grainstone Grain supported rock held by crystalline calcite cement. No carbonate mud is present. The terms floatstone or rudstone are used if 10% of more of the grains are greater than 2mm in diameter.

Boundstone Organically bound rocks produced by algae or other encrusting or binding organisms.

Sedimentary Petrology Mudrocks Textures and Structures Fine grained argillaceous rocks do not show the variety of textures and structures that are present in sandstones and limestones. Colour, bedding


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Sedimentary Petrology and lamination, mineralogy, accessories and organic content are the key areas to describe when dealing with mudrocks.

Colour The colour of a mudrock is a function of its mineralogy and geochemistry, with the main controls being organic content and oxidation state. Red/Purple

Oxygen rich environment Ferric oxide - Haematite

Green/Grey Reducing environment Ferrous Iron - Pyrite

Blue/Multi

Often volcanic tuffs composed ofmontmorillonite/bentonite

Bedding/Lamination Lamination is mainly due to variations in grain size or component types. Size graded lamination may be a result of turbidity action or from suspension characteristics following storm currents. Compositional variation may be a result of seasonal changes in sedimentation or biological activity. Varve deposits of glacial lakes representing spring deposits are typical examples. Siltstone deposits may show small scale ripples and wavy bedding characteristics. Many mudrocks are massive, showing no signs of bedding or lamination. They may however contain concretions or nodules of calcite, siderite, pyrite or chert. These are probably formed at or just below the surface during deposition, and often show evidence of boring or other organic disturbance.

Composition Clay minerals are hydrous aluminosilicates with a sheet or layered structure. The most common is built from silicon-oxygen tetrahedra linked together to form a hexagonal network. Aluminium and magnesium may replace some of the silica.

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Figure 3: Bedding & Lamination Smectite Group

Montmorillonite

Al4(Si4O10)2(OH)4nH2O

Illite (related to muscovite mica)

KAl2(OH)2[AlSi3 (O, OH)10]

Chlorite

Substitution by Fe2+ gives green colour


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Sedimentary Petrology Glauconite

Substitution by Fe3+ gives green colour Kaolinite

(OH)4Al2Si2O5

Sandstones and Conglomerates Textures The texture of a sandstone or conglomerate is largely a reflection of the depositional process. Consideration is given to grain size, grain morphology, surface texture and fabric. The size, shape and degree of sorting are important reservoir characteristics, controlling porosity and permeability.

Grain Size and Sorting This is the basic descriptive element of all sedimentary rocks. The UddenWentworth grain size classification is most commonly used. Whilst grain size does not affect porosity, it has a major bearing on permeability together with grain size distribution, or sorting. When describing sandstones at the wellsite it is important to accurately note these features so that some indication of reservoir characteristics may be inferred from the rock description. Cuttings evaluation produces the first available information regarding the lithology, unless MWD Gamma Ray and/or Resistivity is being run, and, depending on future circumstances, may be the only reservoir information available if logs, cores or formation tests don’t go quite according to plan. In the laboratory grain size and distribution can be measured and statistically interpreted. Neither time nor facilities are available at the wellsite to do this, so visual estimations have to be made, but which nonetheless need to be as accurate as possible and convey the correct information to the reader. Grain size comparator cards are available that can be used under the microscope to assist in this evaluation. Key information to be reported is: • Size of individual grains • Mean grain size of specific cuttings • Mean grain size of the entire lithology Where there is a large variety of grain size, maximum and minimum values should be noted and, where there are perhaps two distinct, but different grain sizes present, it should be referred to as bi-modal. Sorting is generally described using the following terms:

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Figure 4: Grain size card • Very Well Sorted • Well Sorted • Moderately Well Sorted • Poorly Sorted • Very Poorly Sorted Sorting is determined by parent material, grain size and transportation. Sandstones derived from granites are usually more poorly sorted than those derived from sands because of less working being applied. Similarly conglomerates and gravels, having a large grain size will also be more poorly sorted because of the relative lack of transportation compared with sand size grains.


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Sedimentary Petrology Grain Morphology The shape of sand grains is another important factor in reservoir analysis. Both porosity and permeability will be affected. Well rounded, perfectly spherical grains will show the best porosity and angular, elongated grains, the worst. it is necessary, therefore, to describe both these features accurately at the wellsite to give the best possible early indication of potential reservoir quality. Roundness is to do with the curvature of the corners of a grain. The following terms are used: • Very Angular • Angular • Sub-angular • Sub-rounded • Rounded • Well-rounded Sphericity will have some bearing on how well packed the grains may become. Perfectly spherical grains of the same size will show greater porosity than elongate grains.

Grain Surface Texture The surface of sand size grains often have a distinctive texture and give major clues to environments of deposition. The dull, frosted and pitted surfaces of desert sand grains are a distinctive example. Beach sands often show V-shaped percussion marks. Crescent shaped impact marks are sometimes visible on river channels and also some beach sands. Glacial deposits show conchoidal patterns and striations.

Fabric This describes how the grains are packed together. It concerns the nature of boundaries between grains and any preferred alignment. Fluviatile deposits may show alignment with, or sometimes normal to, the prevailing currents. Glacial deposits may also show orientation of clasts parallel to ice movement. It is unlikely that fabric will be able to be determined from drill cuttings or even cores, unless very small scale.

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Figure 5: Grain shape card Cement or Matrix The nature of the material holding the grains together is another important diagnostic feature. The amount and type of cement or matrix will have an effect on porosity and permeability and also influence drilling rate and drill bit selection. Common cements are calcite, silica or iron minerals. Wherever possible the type of cement should be established using visual inspection, colour criteria and dilute HCl. Calcite cements will show a reaction to dilute HCl, whereas silica and iron cements will not. Red/Brown colouration is very distinctive of ferric iron cements such as haematite.

Porosity Porosity has been mentioned above as an important criteria in reservoir analysis. Some estimation of visual porosity needs to be made from drill cuttings analysis. This will be a subjective opinion as again there is not the time or equipment available to make accurate measurements at the wellsite. Experience obviously plays a part here, and so does the analysis of grain texture already made. Clearly a coarse grained, well sorted sandstone with spherical grains showing poor cementation should have good visible porosity. Perfectly spherical, equi-sized grains packed loosely together would have a maximum porosity of 47.6%. This can drop to 26% for a compacted


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Sedimentary Petrology sediment and less when cemented or poorly sorted. The following descriptive terms are used to represent the associated porosity values:

Porosity Description

Amount (%)

Good

>15

Fair

10

Poor

5 - 10

Trace

5 Figure 6: Porosity Terminology

Figure 7: Porosity (cubic Packing) 47%

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Figure 8: Porosity (rhombic packing) 26% It should be noted that very fine grained sandstones may have good intergranular porosity but it may be too small to be visible, even under the microscope, and therefore cannot be recorded in the rock description.

Carbonate Rocks Carbonate Rocks (Limestones and Dolomites) occur throughout geological time and are geographically widespread. They form in warm shallow seas, free of siliciclastic deposition where calcareous skeletal organisms can flourish. Very few carbonates have been produced in temperate latitudes.

Mineralogy Two calcium carbonate minerals are predominant: • Calcite • Aragonite Calcite is the stable form at normal temperatures and pressures and is the primary constituent of all limestones. It has a rhombohedral crystal form and a density of 2.71 gm/cc. Aragonite is unstable and readily converts to calcite, although it is often the primary precipitate and main component of organic skeletons. It has an orthorombic crystal habit, with a density of 2.71 gm/cc.


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Sedimentary Petrology Dolomite is a mixed carbonate in the form CaMg(CO3)2. It consists of alternating layers of calcite and magnesite, in varying percentages and has a density of 2.86 gm/cc. Dolomite rocks are predominately secondary in origin resulting from the reaction of magnesium compounds with calcite or aragonite. Dolomitisation is a very selective process depending on temperature and the nature of the rock. After lithification for example, only shell fragments may be replaced, or at other times only matrix. Dolomitisation often results in enhanced porosity.

Carbonate Components Whilst the mineralogy of carbonate rocks is fairly straightforward, the constituent particles and matrices can be very variable. Unlike siliciclastics, where classification is made from grain size characteristics and environmental interpretation and reservoir properties determined from texture and structure, it is the nature of the grains and cement that give these answers when dealing with carbonates. They are produced at or near the site of deposition with little or no transportation involved. Carbonates are generally made from four components:

• Skeletal grains • Non-skeletal grains • Matrix • Cement Most carbonates are lithified sediments made of discreet and originally loose particles. In some carbonates original grains, cement or structures are not recognisable due to re-crystallisation or other diagenetic activity. Skeletal Grains These are a major contributor to carbonate rocks, and they represent a wide variety of organisms. Most are present as broken shells and fragments but some smaller forms, particularly forams, may show the entire shell. Blue-green algae are common plants, living as either planktonic or sessile forms. Stromatolites are lithified carbonate rocks made by the trapping of sand, silt and mud by algal mats binding the whole structure together. Forams are single celled marine and brackish water animals living either as planktonic or bottom dwelling forms. They are often preserved intact and, because of widespread diversification they are extremely important for dating purposes. During the drilling of high angle and horizontal wells bio-stratigraphers are often retained at the wellsite in

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Sedimentary Petrology order to help the directional driller stay within the reservoir or oil bearing section. Accuracy to within centimetres can be achieved in certain cases. Corals, Bryozoans, Brachiopods, Cephalopods, Gastropods, Bi-valves, Worms, Insects, Echinoids and Crinoids are all represented. The nature of the fossil assemblage can give very clear indications on environments of deposition and energy levels.

Figure 9: Fossiliferous Limestone Non-Skeletal Grains Ooids are spherical to sub-spherical grains consisting of concentric laminae of calcium carbonate formed around a nucleus. They are produced by primary precipitation around the nucleus in shallow marine waters with a gentle rolling action by current or tide activity. By definition ooids are less than 2mm in diameter. Larger than this and they are termed pisoids. A rock formed predominately of ooids is called an oolitic limestone or oolite. Larger grains are sometimes composite ooids that have formed by small ooids being enveloped by concentric laminae.


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Sedimentary Petrology Oncoids are sand to pebble sized particles with a concentric, but irregular multi-layered structure. Often they are coated with algae or algal mats. Peloids are spherical, cylindrical or angular grains made of microcrystalline calcite showing no internal structure. The origin of these grains is diverse and often doubtful. They may have originated as faecal pellets, calcareous algae, altered and broken shell fragments or re-crystallised mud clasts. Lithoclasts are fragments of rock which have been transported and reworked prior to deposition. Their presence suggests the proximity of an outcrop from which the clasts are eroded.

Figure 10: Ooids Microcrystalline Calcite (Lime Mud) This is fine grained dark coloured matrix, equivalent to argillaceous mud. It may form from direct precipitation as grey-white aragonite crystals or from the fragmentation and bio-erosion of grains and pellets.

Cement This is the term for crystalline carbonate acting as the bonding agent or matrix and coarse grained enough to show crystal structures and features under the microscope. In ancient sediments it is almost always calcite rather than the unstable aragonite.

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Sedimentary Petrology Dolomite Partial or complete dolomitisation of ancient sediments is a common feature. The conversion of calcite or aragonite to dolomite may take place soon after deposition or a long time later. The formation of dolomites is still somewhat uncertain, but seepage-reflux of seawater by capillary action and flooding is one proposed mechanism. Evaporative pumping in lagoonal supra-tidal environments is another.

Porosity Porosity in Carbonate rocks can be divided into two main types: • Primary Framework porosity formed by rigid carbonate skeletons such as coral Interparticle porosity in carbonate sands Fenestral porosity in carbonate muds • Secondary Moulds, vugs, cavernsIntercrystalline porosity (dolomitisation) Fracture porosity


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Figure 11: Carbonate Porosity Most carbonate reservoirs are important because of secondary porosity since primary inter granular or intra granular porosity is often very small or irregular and isolated. The chalk reservoirs of southern Norway and Denmark have hydrocarbons in vertical fractures caused by shallow doming. This type of porosity is almost impossible to detect in drill cuttings or even cores, but can be inferred from drill rate, rotary torque characteristics, MWD and surface mounted drilling mechanics instrumentation and from MWD and wireline logs. Sonic logs will only detect primary porosity since the fastest compressional sound wave is the one that will be detected and evaluated. This wave will have travelled through the most dense part of the rock and will show regular interparticle porosity. The density and neutron porosity logs however, will show all types of porosity so that a comparison of apparent results with these and the sonic log should show areas dominated by secondary porosity.

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Sedimentary Petrology Evaporites Evaporites are chemical sediments which have precipitated directly from water following salt concentration caused by evaporation. Common evaporite minerals are halite (Rock salt), gypsum and anhydrite, but there are many others depending on climate and chemical availability.

Mineral

Composition

Halite

NaCl

Gypsum

CaSO4.2H2O

Anhydrite

CaSO4

Sylvite

KCl

Carnalite

KMgCl3.6H2O

Figure 12: Evaporites

Evaporites are of great economic importance, having a wide range of applications. They are important in the oil industry by acting as seals to hydrocarbon reservoirs, or overpressured zones, and by acting as climatic indicators and marker horizons. Salt deposits are commonly cyclic, ranging from very thin beds to some tens of metres thick. They usually consist of massive gypsum and anhydrite, alternating with limestones, marls and infrequent salts. The Permian Zechstein sequence of NW Europe shows many repeated cycles of anhydrite/gypsum passing upwards into halite with thin beds of highly soluble bittern salts (potassium and magnesium chlorides and sulphates) at the top. Precipitation is thought to occur in two modes: • Subaqueous precipitation from moderately deep standing bodies • Subaerial precipitation form shallow pools and salinas, with subsequent replenishment.


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Sedimentary Petrology Gypsum and Anhydrite These minerals possess distinctive structures and textures and are prone to replacement, recrystallisation and solution. Both minerals may precipitate directly, but on burial to depths of more than a few hundred metres, only anhydrite is present. With subsequent uplift, all anhydrite is converted to secondary gypsum. The main differences between gypsum and anhydrite for field recognition are in hardness and density.

Mineral

Moh’s Hardness

Specific Gravity

Gypsum

1-2

2.37 gm/cc

Anhydrite

3.5

2.9

Halite Halite commonly infills large sedimentary basins, and is the main evaporite mineral of many saline lakes. Rock salt may be massive, layered, bedded or mixed with siliciclastic sediments. It has a cubic form and is often visible in cuttings samples as white to colourless grains, although impurities can produce mottling or banding of greys, blacks, reds and pinks. It is very soluble in water and obviously has a distinctive salty taste.

Other Evaporites Potassium and magnesium salts are highly soluble and the last to precipitate in the evaporite sequence. Because of their solubility, diagenetic changes when in contact with residual brines and fresh groundwater is inevitable. Indeed many of theses mineral assemblages are probably secondary in origin.

Drilling Practices It is common to drill massive salt sequences with salt saturated, or even oil based mud systems. In these cases evaporite cuttings will be seen at the surface, and samples can be treated in a normal manner. If thin or partially saline formations are drilled with non saturated muds then most of the samples will be lost to solution. It is then necessary to look for secondary signs of evaporites:

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Sedimentary Petrology • Change in ROP • Smooth ROP for massive sequences • increased mud salinity • Increased mud viscosity • Reduction in background gas • Remaining cuttings eroded and reworked

Other Chemical Rocks Chert Chert is a general term for fine grained siliceous sediment of chemical, biochemical or biogenic origin. It is usually a dense, very hardrock which splinters with a conchoidal fracture when hit.Other names, such as Flint, representing nodules found in Cretaceous Chalk, or Jasper, signifying a red variety due to haematite content, are commonly used.Cherts are usually divided into bedded and nodular varieties. Most chert encountered in hydrocarbon drilling operations is of the nodular type, present in carbonate host rocks. Nodules vary in size and shape from small to large and sub spherical to irregular. They may be concentrated along bedding planes. Many such nodules are secondary features, perhaps starting out as calcareous grains such as peloids or ooids. Biogenic silica may dissolve and re-precipitate by filling in holes or pores and later replacing grains and shell fragments. These represent growth points which subsequently become nodules.

Coal Most coals are humic, formed from woody plant material. Others are called sapropelic from algae, spores and other plant debris. There is a natural progression of humic coals from peat, through brown and bituminous to anthracite. Most of the changes are temperature induced. Increasing rank leads to increased carbon and reduced volatile content. Coals are typical of the late Devonian and Carboniferous periods and often occur at the top of coarsening upward deltaic cycles.


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Cuttings Sampling & Evaluation Introduction The importance of the cuttings samples cannot be over-stressed. There is no substitute for representative cuttings samples accurately correlated to the depth from which they came.

Sample Collection & Preparation Every rig has shaker screens for separating the cuttings from the mud as they reach the surface. If the screen mesh is small enough to remove small cuttings and the job is in an area where there is reason to believe that no unconsolidated sands will be encountered, the shaker screen will provide a collection point for composite sampling (i.e. interval sampling). However, when unconsolidated sands pass through the screen, they can be extracted from the mud by desanders and desilters and a sample collected from them for examination. This sample should be considered along with the shaker screen and composite samples when making an overall evaluation. Cuttings samples should be taken at regular intervals as often as possible, and never at intervals greater than 15 minutes. The sample bags should be filled progressively to give a representative sample of the whole interval. Samples should also be taken when changes in drill rate or background gas are noticed as these often indicate a change in formation lithology or porosity.

Figure 1: Shale Shaker


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Cuttings Sampling & Evaluation Care should be taken at the shale shaker to ensure that a representative sample is collected with minimum cavings. The desander and desilter outlets should be checked regularly for fine sand which might pass through the shaker screen. Washing and preparing the cuttings are probably as important as the examination itself. In hard rock areas, the cuttings are usually quite easily cleaned, in which case it is a matter of washing the sample in a sieve to remove the mud film. In many areas, however, particularly areas and zones of loose sands and shales, it is more difficult and requires several precautions. Primarily, the clays and shales are often soft and of a consistency which goes into suspension and makes mud. Care must be taken to wash away as little of the clay as possible; and, in determining the sample composition, account must be taken of any clay that is washed away.

Figure 2: Sample Collection After the cuttings have been washed to remove the mud, they are washed through a 5-mm sieve. It is generally considered that newly drilled cuttings will go through the 5-mm sieve and that material which does not is cavings and may be discarded. Cuttings from wells drilled with oil-based or oil-emulsion muds are usually more representative of the drilled formation than cuttings drilled with water-based mud because the oil emulsion prevents sloughing and dispersion of clays and shales into the mud. At the same time, washing and handling cuttings drilled with this type of mud poses somewhat of a problem; they cannot be cleaned by washing in water alone. It is usually nec-

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Cuttings Sampling & Evaluation essary to wash the cuttings first in a detergent solution to remove the oil mud. Naturally, oil show evaluation can be complicated when oil-based muds are used. An oven mounted in the logging unit is used to dry a portion of the cuttings sample after it has been washed, while a representative sample of the washed cuttings are examined under the microscope.

Cuttings Examination Samples are examined under the microscope primarily for lithology, staining and porosity; the objective is to depict changes of formation and the appearance of new formational materials. The microscope and ultraviolet light are used as complementary tools in reconstructing the characteristics of the originating strata. An estimate of the percentages of lithology, staining and porosity are made with great care since factors such as grain shape and size, colour, distribution, etc., may affect the apparent relative percentages. There are many potential sources of contamination to consider when undertaking estimates of lithology percentages, examples of which are:

Figure 3: Cuttings Examination

Cavings Cuttings from previously drilled intervals rather than from the current interval. Although ditch cuttings are first washed through a coarse sieve to


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Cuttings Sampling & Evaluation remove cavings, some may remain in the sample. Cavings may be recognised as generally large, splintery rock fragments that are often concave or convex in cross-section. They are lithologically identical with formations from higher sections of the open hole. If found in large quantities, this may indicate a serious underbalanced mud condition or a situation where rotation is too fast and the stabilisers are catching on the side of the hole.

Recycled Cuttings If cuttings are not efficiently removed from the drilling fluid at the shale shakers, desanders and desilters, they may be recycled through the mud system. Recycled cuttings may be recognised as small, abraded, rounded rock fragments in the sample.

Mud chemicals Some mud chemicals may be confused with rock types. Lignosulphonate, for example, may resemble lignite, and bentonite gel may erroneously be identified as Montmorillonite clay in a poorly mixed mud system. Moreover, lost circulation material (LCM) such as nut shells, fibres and mica flakes, is a common source of contamination in lost circulation zones.

Cement Cement contamination is usually encountered when drilling after casing or while sidetracking. Cement may be mistaken for siltstone but can be readily identified by testing with phenolphthalein solution in which cement stains purple due to its high pH.

Metal Metal is occasionally found in samples and frequently originates from wear of the inside of casing by the drillstring. This is often remedied by the use of rubber drillpipe protectors.

Unrepresentative samples In some cases, samples may be totally unrepresentative of the formation at bottomhole. For example, in evaporite sections drilled with a water-based mud, salts dissolve and there is no lithological indication of their presence in lagged samples. However, evaporites can still be recognised by good logging practice: • Evaporites generally drill at rates of 40 to 60 ft/hr • Gas values through evaporites will be very low if not zero

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Cuttings Sampling & Evaluation • There will be poor or no returns at the shale shakers • Limestones and dolomites are frequently found in association with evaporite deposits • Anhydrite sections can usually be identified by BaCl solution which produces BaSO4 precipitate • The chlorides content of the drilling fluids should increase very significantly. A single layer of cuttings should be used for percentage estimation, and care should be taken to select a representative sample from the sieve because a large degree of shape and density sorting occurs during washing. Once the percentages of the various constituents have been estimated, the sample description is made in a logical order similar to that detailed below:

Figure 4: Sample Washing


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Cuttings Sampling & Evaluation

Figure 5: Shaker Screen and Sieve sizes

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Cuttings Sampling & Evaluation Sample Descriptions Name Clastics Claystone

blocky, amorphous

Shale

Indurated, hard, fissile

Siltstone Sandstone

Carbonate Limestone

fast reaction to acid. Violent, grain moves around, abundant CO2

Dolomite

slow, less violent reaction to acid

May use a classification scheme according to Operator requirements, such as: Dunham Mudstone, Packestone, Wackestone, Grainstone, Boundstone

Colour Describe as is or use American Geological Society Rock Colour Chart. The colour chart has the benefit of consistency and, like any coding scheme, enables both the author and the recipient to fully understand the message; in this case the rock colour. As well as the colour other information should be included: Intensity:

bright, dull

Distribution: even, spotted, banding etc.

Hardness of the rock, not the mineral(s), indicating compaction and/or cementation. Use the sample probe to evaluatehow easily the rock breaks Typical descriptive terms are: Soft, friable, firm, moderately hard very hard


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Cuttings Sampling & Evaluation Claystones:

Check reaction to 10% HCl and Water Acid:

Breaks

Hygrofissile

Water:

Breaks

Hydrofissile

Swells

Hydroturgid

Cement Amount:

Poor, moderate, well (cemented)

Type

calcite, silica, iron (commonly red.brown colour) etc. check reaction to acid for calcareous content

Texture Clastics:

Use grain size chart to evaluate: Grain size, shape, sorting

Carbonates: Types of grains

Shell fragments, pellets

Type of cement

Crystalline calcite, lime mud

Porosity Trace, fair, good estimates of visual porosity

Accessories Fossils Minerals

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Iron:

Limonite, haematite, glauconite (green, indicates marine conditions)

Calcite:

white, reacts with acid


Cuttings Sampling & Evaluation Pyrite:

gold, reducing conditions

Carbonaceous:

black

Chlorite:

green

Biotite mica:

brown/black

Muscovite mica: colourless

Oil Show Evaluation Stain

Colour

Brown

Intensity

light medium dark

Odour

(Smell)

Fluorescence

Colour

Brown – Yellow/gold – blue/white – white – colourless

Intensity

dull, bright etc.

Distribution

even, spotted, banding

Solvent Cut Reaction

yes/no

Colour

yellow/gold - milky white or equivalent)

Speed

slow, fast, instantaneous

Style

Diffuse: no shape Streaming: rivers/stream Blooming: dense, viscous

White light


Stain colourlight – dark brown

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Cuttings Sampling & Evaluation Oil Show Evaluation Evaluation of oil in the cuttings (and mud) should proceed from inspection under the microscope to inspection in the ultraviolet-light box. Tests and visual inspection should be performed upon mud, unwashed and washed bulk cuttings, as well as individual grains.

Figure 6: Oil Show Evaluation

Oil Staining Any stain or colouration that is not just superficial, except in the case of oil from fractured reservoirs, warrants checking with a fluoroscope or solvent test. The amount, degree and colour of the staining should be noted, such as:

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Cuttings Sampling & Evaluation • No visible oil stain • Spotty oil stain • Streaky oil stain • Patchy oil stain • Uniform oil stain Colour and intensity of the stain should also be included as this will give an indication of API Gravity. A black asphaltic residue is indicative of dead, residual oil lacking volatile components. Sample chips that bob to the top in water or acid should be checked with a fluoroscope. This bobbing may be due to a surface coating of oil on the cuttings, and a check should be made to see whether oil staining goes right through the chips. Note that oil-base muds will cause the sample chips to be oil soaked.

Natural Fluorescence At the microscope, the geologist should select those cuttings that have visible oil staining and place a representative selection on a spot plate. They are then transferred to the UV light box where they are inspected for fluorescence and solvent cut. The intensity and colour of oil Fluorescence is a most useful indication of oil gravity and mobility. Decreased intensity and darker colour will commonly accompany decreases in gravity. Water-wet or residual oils, which tend to be poorer in lighter, more volatile hydrocarbons, will have the fluorescence colour representative of their gravity, but will commonly be paler in colour and less intense.In all fluorescence tests, it is important to observe a fresh surface. Since fluorescence may also be caused by certain minerals or contaminants such as pipe dope, care must be taken not to confuse these with true formation hydrocarbons. A mineral fluorescence will not leach in a solvent, therefore no cut fluorescence will be seen. The intensity of the fluorescence may yield important clues on the fluid content of the rock; for instance, though a series of samples are uniformly fluorescent, a lessening of intensity may indicate a transition from oil- to water-producing zones. When fluorescence is not attributable to minerals or contaminants in a sample, then this is taken as proof of oil being present in a rock and allows an estimation and description of the amount of oil in the rock cuttings. The colour of crude-oil fluorescence can be used to make quantitative identification of the approximate API gravity of the crude. Colours range from brown to gold to green, yellow to blue-white with a variety of colours and shades


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Cuttings Sampling & Evaluation between. The darker colours, browns and oranges are associated with the heavier crudes, the lighter colours are indicative of the lighter oils. Refined oils such as diesel and pipe-dope will give a bluish-white fluorescence, and often very light oils or condensates and heavy tars will not fluoresce at all. Experience shows the following rough correlation: The degree of oil fluorescence should be immediately noted and may be described as: • None • Spotty • Streaky • Patchy • Uniform The colour should be noted along with the percentage of the sample fluorescing, and more precisely, the percentage of the reservoir rock fluorescing. The brightness of the fluorescence is important. Below the oil/water interface, the cuttings, while still carrying a lot of oil and gas, may show a marked change in intensity- the fluorescence becoming dull and losing it’s original bright sharp colour. Fluorescence checks should be done immediately on a sample. If the cuttings are left exposed to the atmosphere, the fluorescence tends to dull appreciably due to the loss of volatiles. This is accelerated under heat lamps and even under the microscope. Along with the above description of the fluorescence a note should be made of how the fluorescence is distributed throughout the rock. In most cases the fluorescence will be found around the grains in the matrix of the rock, but in some areas the reservoir rock may be of low porosity but highly fractured, with all of the fluorescence and staining occurring along the fractures and often never entering the parent rock more than a few millimetres (if at all). This is the case in fractured granite and dense fractured limestone and dolomite reservoirs. Care must be taken in the evaluation, as the porosity and permeability of the parent rock are no longer important in the determination of a field’s producing capabilities. The production is dependent upon the amount of fracturing present, it’s interconnection, and the amount of recrystallisation along them. A true idea of the possibilities of such a reservoir can be obtained only from taking cores - not from drill cuttings.The mineral fluorescence given by specific rock types are given below and will not give a solvent cut:

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Cuttings Sampling & Evaluation Solvent Cut Fluorescence Solvent cut is valuable in assessing fluorescence and allows deductions to be made of oil mobility and permeability of the reservoir. By removing the oil from the coloured background of the cutting, the solvent allows a better estimate of fluorescence. The way in which the solvent cut occurs, e.g. instantly for high gravity oils, more slowly for more viscous lower gravity oils, or irregularly streaming from limited permeability, also yields useful information. If no cut can be obtained from a washed cutting, the test should be repeated on a dried cutting, crushed cutting or after application of dilute hydrochloric acid. This will produce the required cut and yield further evidence on permeability or effective porosity. After the cut solvent has evaporated, a residue of oil remains in the cut dish, displaying the oil’s natural colour. Examination of mud and unwashed cuttings for oil may not be so discriminating as individual cuttings, but it can yield general information on oil type. 200 cc of mud is poured into a dish and observed for fluorescence in the UV box. Droplets of oil may be seen popping at the surface. Then, 100 cc of water is added and the sample is observed again. This helps lower the mud’s viscosity to aid oil escape. It also separates the mud and oil, allowing a small oil sample to be skimmed off the water surface. Finally the mud and water are stirred together, and the sample is left for 30 seconds or longer to allow all of the oil present to accumulate at the surface. If a high gravity oil or condensate is suspected, the sample should be observed throughout this period. Otherwise evaporation due to the heat of the UV light may lead to a pessimistic or false conclusion. This procedure is repeated with 200 cc of unwashed cuttings. In this case, working the sample with the fingers can help to free oil droplets. The droplets rise through the water and appear to pop on the surface as gas is released. Oil effects observed from mud or unwashed cuttings under UV light are commonly classified into five characteristic types, as follows:

Type 1: 1mm pops, scattered and few in number; this type is frequently associated with oil found in shale, along bedding planes, fractures, and sandstone containing very slight traces of residual oil.

Type 2: 2mm pops or larger, few in number commonly noted in large fractures and residual oil in sandstone; may be dull and streaky, associated with low gas readings.


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Type 3: Pinpoints common, along with 2mm or larger pops; this type of fluorescence frequently observed from sections with fair amounts of oil.

Type 4: Common to abundant pinpoint; normally associated with good to fair shows of oil.

Type 5: Abundant pops 2mm and larger, are frequently found associated with good shows. In higher gravity oil, the pops surface and spread rapidly. Gas can usually be seen escaping as the oil pops to the surface.

The show, once fully evaluated, should be graphically displayed on the Mud Log. An accompanying description should include: Free Oil In Mud:

colour, fluorescence, amount

Sample Odour:

type, strength

Visible Staining:

colour, amount, evidence of surface wetting

Cut:

rate, colour, fluorescence (colour/intensity) residual stain

Salinity or conductivity measurements should be taken continuously throughout the show. The reservoir evaluation presented on the Mud Log may be augmented by a Show Report.

Hydrocarbon Analysis Scorechart Another method for quantifying a show, rather than simply describing it as good - poor etc., is to use a method of scoring the various parameters used in evaluation. The scorechart shown on the following page is an example of this method. The logger evaluates each of the show parameters and adds up the points according to the chart, arriving at a total which can then be translated to a rating and a descriptive form as shown in the table below. In a sense, this method takes away some of the subjective nature of show evaluation, where different geologists would weigh the parameters differently and perhaps arrive at different conclusions.

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Cuttings Sampling & Evaluation Hydrocarbon Scorechart


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Point Range

Score

Show Rating

0-15

1

No Show/Poor Trace

16-30

2

Poor Trace

31-45

3

Trace

46-60

4

Good Trace

61-75

5

Moderately Fair

76-90

6

Fair

91-105

7

Moderately Good

106-120

8

Good

121-130

9

Very Good

131-143

10

Excellent



Oil Show Descriptions, based on dry cuttings, using spot plates and hexane Oil Stain %

Direct Natural Fluor %

Solvent Cut Fluor %

Natural Cut Colour

UV Residue Colour

Natural Residue Colour

Show Rating

Comments

In a gas zone the solvent colour is generally clear, with small amounts of oil the solvent starts to take colour. Use this as your lower show rating. Basic change from 12 is presence of discernable Lt tea Natural Cut Colour. Occasionally traces of free oil droplets. Natural cur colour and residue becoming darker. The residue fluor becomes more intense described as bright, pale yellow. Common free oil droplets Good cuts with welldeveloped residue ring/fluorescence. Free oil droplets.

Pchy 20-100% v pa crm

Pchy 30-100% pa yel/wh

Slow diff pa Blu/wh

Sli discolext. wk tea

Fnt blu/yel

Fnt yel/brn

1

Still pchy but w/incrsg stn, 60100% palt crm Bcmg more uniform 80-100% lt-mod crm

Variable from 50100% dull-pa yel

Fast inst diff blu/wh

Wk-lt tea

Bcmg brighter yel/wh

V lt brn

2

From 80100% yel/whmod yel

Inst diff pa wh w/com. Strmg mlky wh

Lt-m tea

Bright pa yel

Lt brn

3

Uniform mod-dk crm

Uniform can vary from bridull yel

Good m tea

Bri yel

M brn

4

Dk crm to almost brn in some fields. Abdt free oil Brn to dk brn usually with abdt free oil

100% brimod yel

Inst diff pa-wh, com strgm, solvent will slowly turn mlky wh Inst diff mlky wh, bcmg yel/wh

Dk to v dk tea

Deep yelgold

Dk brn

5

Strong tea Natural Cut with dark residue

Inst diff yel/wh

Coffee

Gold-dk brn

V dk brnblack

6

Coffee black Natural Cut

100% mod- deep yel

These are basic guidelines for Oil Shows. The Natural Cut Colour and Natural Residue are the most reliable indicators, the lower the Sw the darker the colour. DO NOT simply increase/decrease the show rating based on LWD quick-look. This form is standardised and should be used as a guide by all well site geologists.

Figure 7: Hydrocarbon Evaluation


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MWD Overview MWD/LWD Services Measurement While Drilling is a technique for measuring directional survey and petrophysical rock properties downhole, during drilling, and transmitting this data to the surface for real-time evaluation. The service developed during the late 1970s and is now an integral part of formation evaluation in complex and difficult wells. Applications for MWD services include: • Survey Data • Open Hole Petrophysics • Real Time Data • Tough logging conditions (TLC) where traditional wireline logging is not possible • Alternative to tubing conveyed logging operations

Figure 1: General MWD Tool

Measurements There are generally two types of measurement while tools: those which take directional surveying data and those which take formation evaluation data: • MWD Inclination Azimuth Tool face

Petrophysics

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MWD Overview • LWD Gamma Ray Resistivity Formation Density Photoelectric Effect Neutron Density Sonic • Pressure While Drilling Annular Pressure Formation Pressure • Wellbore Stability • Acoustic Caliper • Drilling Mechanics Vibration Downhole Torque Downhole WOB Mud Temperature

General Features Drill Collar MWD and LWD sensors are housed in a drill collar with an OD suitable for the hole size being drilled. Typically these have been 6¾” and 8½” to enable operation in 8½” to 17½” hole sizes. Recently however most companies have introduced slimhole versions of their tools in 4¾” drill collars for use in 6½” and smaller hole sizes. Indeed Baker Hughes Inteq have been field testing a 3?” diameter Rotary Steerable drilling tool with associated LWD sensors for 3?” to 4¾” holes.

Sensor & Control Unit The sensors are located in the centre of the drill collar to allow mud flow. A microprocessor unit is included along with downhole memory for storing data which is unable to be transmitted in real time.

Power Supply Power supply comes from batteries or downhole generation. Batteries are usually lithium-chloride types. Lithium provides the highest capacity (ampere-hours or "Ah") per unit weight of all metals, making it an ideal material for a lithium anode. Lithium systems offer distinct advantages over other battery systems,

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Petrophysics

MWD Overview especially with respect to long life, reliability and capacity. Batteries also enable logging while tripping if mud is not being circulated and independently of mud flow and hydraulics variations.

Figure 2: Basic Tool Configuration Battery Power A lithium power source offers a significant advantage if: • A high voltage is needed (i.e. 3.0 to 3.9 volts per cell) • A recharging circuit is not available or too costly • The power source has to be as light weight as possible • Long shelf life is required • A wide temperature range is required • Reliability is crucial • Extremely high energy density is needed • Environmental concerns such as temperature, vibration or shock are especially severe

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MWD Overview • Your application demands a continuous source of power for extensive periods of time Disadvantages with battery power include: • Finite life so compromises with real-time transmitted data have to be made concerning data types and frequency related to expected continuous drilling time • Not re-chargeable so disposal is a problem as they are classified as hazardous waste: • These batteries are a characteristic hazardous waste due to toxicity, ignitability and reactivity. • The temperature range on a lithium battery is 40°F to 185°F. Generated Power Power can be generated using the mud flow driving a turbine to power an alternator. This has the advantage of having no time limits although it requires mud flowrates between certain, pre-set ranges, to function. Some MWD tools use a combination of both power supply systems.

Data Transmission System During the early development stage of MWD services many alternative forms of data transmission systems were investigated. During the 1970s there were drill collar mounted MWD sensors (accelerometers and magnetometers) to measure inclination and azimuth connected to the surface by a wire cable which exited the collar via a side-entry sub and provided a continuous, real time surface display. This could only work if there was no drillstring rotation which was the case with early bent-sub and motor directional drilling tools which used a mud-driven turbine to turn the bit which was attached to a bent housing above the motor. Because of the long overhang below the motor and the amount of offset of the bit from the centreline of the drillstring, no string rotation was possible. Thus the tool could only build or drop hole angle whilst turning right or left and was unable to drill straight. Using this early form of MWD was very useful for geometric steering of these build or drop sections. With developments in directional drilling tools, however, it became possible to drill in either rotary (drillstring rotation) mode for straight drilling or oriented (using the motor only) mode for drilling build or drop sections. This meant that the hardwire cable form of data transmission became untenable.

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Petrophysics

MWD Overview Other data transmission systems were then investigated and these included the potential of using the drillstring as a conductive medium or of embedding a conductive wire within the wall of the drillpipe. Drillstring Data Transmission At least 10 patents have been issued during the last 50 years in attempts to create drill pipe telemetry, using both hardwired and induction-based transmission across connections, but both of these have failed. Like all hard-wired jointed systems thus far, the electric contacts at the drill pipe joints proved too difficult to reliably align, allow perfect contact, and not leak under field conditions. Induction across couplings has a host of problems, most notably signal/field losses and downhole power-boosting. It was realized early on that hard-wired drill couplings, no matter how well designed, would probably always be prone to failure as the number of connections and the many connect/disconnect cycles grew. Therefore, induction was chosen as the means to transmit data from joint to joint for more serious reach. This, however, carried with it many problems to overcome. It is only very recently that Grant Prideco has developed IntelliPipe which is currently undergoing research and development including field trials. Whilst very fast data transmission rates can be achieved, any hard-wired or induction based drillstring telemetry system is likely to be very expensive to initiate and, of course, requires the total replacement of the existing drillstring.

Figure 3: Grant Prideco Intellipipe

Petrophysics

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MWD Overview

Figure 4: IntelliPipe Surface Swivel Mud Pulse Telemetry Because of the cost and technical difficulties associated with developing drillstring data transmission systems, mud pulse telemetry has been used by all the commercial vendors over the last twenty-five years. Downhole valves or modulators are used to create pressure pulses or carrier waves which are superimposed on the normal pump pressure (or standpipe pressure) signal and transmitted through the mud to the surface where they are seen by very sensitive standpipe pressure transducers as a form of binary code. The data is sent to sophisticated decoding computers for analysis. The mud pulses are carried through the mud at roughly the speed of sound in mud (i.e. 4000-5000 ft./sec or 1200-1500 m/sec), giving virtually instantaneous data transmission. However data transfer rates with mud pulse telemetry are very slow. Early tools worked at 1 – 3 bps; more recent tools work at around 10-12 bps whilst the latest generation Schlumberger tools from their EcoScope™ system works at around 16bps which is enough for 2 data points/ft at logging speeds of up to 450ft/hr. This needs to be compared with hard-wired systems though which are capable of 2 million bps (2Mbps). Typical current operational specifications:

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MWD Overview

Survey Time

44seconds 92seconds

Toolface Update

15 seconds

Gamma Ray Update

28 seconds

Collar Size

4¾- 9½ ins

MTBF

300 hrs +

Maximum Temp (operating)

300°F (150°C)

Maximum Temp (survival)

350°F (175°C)

Mud Pulse Telemetry Systems Positive Mud Pulse Telemetry

Positive mud pulse telemetry (MPT) uses a hydraulic poppet valve to momentarily restrict the flow of mud through an orifice in the tool to generate an increase in pressure in the form of a positive pulse or pressure wave which travels back to the surface and is detected at the standpipe.

Figure 5: Positive Mud Pulse Telemetry

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MWD Overview Negative Mud Pulse Telemetry

Negative MPT uses a controlled valve to vent mud momentarily from the interior of the tool into the annulus. This process generates a decrease in pressure in the form of a negative pulse or pressure wave which travels back to the surface and is detected at the standpipe.

Figure 6: Negative Mud Pulse Telemetry Continuous Wave Telemetry

Continuous wave telemetry uses a rotary valve or “mud siren” with a slotted rotor and stator which restricts the mud flow in such a way as to generate a modulating positive pressure wave which travels to the surface and is detected at the standpipe.

Figure 7: Continuous Wave Telemetry

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Petrophysics

MWD Overview Electromagnetic Telemetry

The electromagnetic telemetry (EMT) system uses the drill string as a dipole electrode, superimposing data words on a low frequency (2 - 10 Hz) carrier signal. A receiver electrode antenna must be placed in the ground at the surface (approximately 100 meters away from the rig) to receive the EM signal. Offshore, the receiver electrode must be placed on the sea floor. Currently, besides a hardwire to the surface, EMT is the only commercial means for MWD data transmission in compressible fluid environments common in underbalanced drilling applications. While the EM transmitter has no moving parts, the most common application in compressible fluids generally leads to increased downhole vibration. Communication and transmission can be two-way i.e. downhole to uphole and uphole to downhole. The EM signal is attenuated with increasing well depth and with increasing formation conductivity.

Figure 8: Electromagnetic Wave Telemetry

Memory Most commercial real-time and recorded only formation evaluation tools have an enhanced memory capability. This system provides for storage of raw data and permits storage of data at higher rates than is possible with real-time transmissions. The memory system is also used for retrieval of formation data if only toolface data are transmitted when steering. Data storage also provides data recovery in case of transmission problems. For example, if real-time data are lost

Petrophysics

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MWD Overview due to surface detection problems, memory data can be used to fill in the missing information. The chances of memory filling up on long bit runs is a possibility but rare in today’s market.

MWD Services (Directional Survey Data) MWD tools use solid state accelerometers and magnetometers to measure: • Borehole Inclination • Borehole Direction (Azimuth) • Tool Face Orientation (Azimuth)

Accelerometer Accelerometers are used to measure the earth’s local gravitational field. Each accelerometer consists of a magnetic mass (pendulum) suspended in an electromagnetic field. Gravity deflects the mass from its null position. Sufficient current is applied to the sensor to return the mass to the null position. This current is directly proportional to the gravitational force acting on the mass. The gravitational readings are used to calculate the hole inclination, toolface, and the vertical reference used to determine dip angle.

Magnetometer Magnetometers are used to measure the earth’s local magnetic field. Each magnetometer is a device consisting of two identical cores with a primary winding around each core but in opposite directions. A secondary winding twists around both cores and the primary winding. The primary current (excitation current) produces a magnetic field in each core. These fields are of equal intensity, but opposite orientation, and therefore cancel each other out such that no voltage is induced in the secondary winding. When the magnetometer is placed in an external magnetic field which is aligned with the sensitive axis of the magnetometer (core axis), an unbalance in the core saturation occurs and a voltage directly proportional to the external field is produced in the secondary winding. The measure of voltage induced by the external field will provide precise determination of the direction and magnitude of the local magnetic field relative to the magnetometer’s orientation in the borehole. In the MWD drilling environment, there are many sources of magnetic interference that can cause inaccurate directional measurements. A ferromagnetic steel object that is placed in a magnetic field will become magnetized. The amount of induced magnetism is a function of the external field strength and magnetic permeability of the object. In order to prevent magnetic interference, the directional

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Petrophysics

MWD Overview survey instrument is housed in a nonmagnetic stainless steel collar. The MWD tool is usually arranged in a section of the bottom-hole assembly (BHA) which is made up of a series of non-magnetic collars to reduce the impact of the drilling assembly's steel components on the magnetic field at the location of the survey sensor. Other sources of magnetic interference may be caused by proximity to iron and steel magnetic materials from previous drilling or production operations, magnetic properties of the formation, and concentrations of magnetic minerals (iron pyrites, etc.) in excess of six percent. Local magnetic anomalies may also be present and the strength of local magnetic interference may change with magnetic storms for example.

LWD (Formation Evaluation Logging While Drilling) Gamma Ray The Gamma Ray log has been a fundamental part of the petrophysical logging suite for many years. It is used as a basic geological correlation tool, for depth matching and for general geological interpretation. In LWD tools it is important for geosteering in that it gives primary information about finding and drilling reservoir sections. Most vendors tools use scintillation detectors to make gamma ray counts of emitted radiation from rocks and minerals in the subsurface. Scintillation detectors use a crystal of thallium-doped sodium iodide which emits light flashes or scintillations when a gamma ray interacts with the crystal. A high voltage photomultiplier tube captures the scintillations, amplifying them into an electrical signal in the form of a count rate. Gamma rays are measured over a specified time in order to collect enough counts to reduce statistical scatter. The data is normally recorded and presented as API Gamma Ray Units as used in Wireline Logging operations. Gamma rays are produced from the radioactive decay of isotopes of Uranium, Thorium and Potassium. Typical reservoir rocks, (sandstones, limestones and dolomites) are usually deficient in these elements whilst many clay minerals have high concentrations of all three. Mudrocks therefore tend to give high gamma ray counts whilst reservoir rocks tend to have low values. This is complicated with variations in rock mineralogy which calls for more detailed and careful interpretation. Environmental factors will also affect gamma count rates. Mud types, mud density, thin beds and hole size will all affect the response.

Petrophysics

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MWD Overview MWD and Wireline Gamma Ray Comparisons Some fundamental differences exist between MWD and wireline gamma ray data, and only rarely do the logs overlay exactly. Statistical variations associated with MWD logs are often considerably less than those of wireline because wireline logging speeds are greater (1800 ft/hr) than MWD average rates of penetration (200 ft/hr). MWD bed resolution is improved, compared with wireline, because of the slower logging speeds. MWD formation measurements are carried out before significant hole enlargement occurs, resulting in data requiring less correction. Also, MWD logs suffer less mud volume attenuation since the gamma sensors are housed in drill collars that typically have larger OD's than the wireline sondes. Differences are often noticed in run-by-run comparisons of wireline gamma ray logs due to centralization practices. Detected radiation, particularly the lower energy gamma rays of thorium and uranium, is more attenuated by the thick metal housing of the MWD collar. MWD collars range from wall thicknesses of 1" to 3", while wireline gamma ray tool housings are typically 1/8” to 3/8”. Thus, the MWD measured gamma ray spectrum is biased to enhance potassium relative to thorium and uranium. For this reason, the MWD gamma ray data will be lower than wireline values in formations rich in thorium and/or uranium. After borehole correction, the two types of logs may have identical values, particularly in formations with spectral characteristics similar to the API pit. It should also be noted that the logging speed of LWD Gamma tools may be variable within the same formation even though the ROP may have been consistent. This depends of the offset of the Gamma ray sensor from the bit and the thickness of the bed being drilled. For example, if the gamma ray sensor is 5m behind the bit and there is a 5m sandstone bed in between shales then the sandstone will be logged by the gamma ray tool at the ROP of the shales and not of the sandstone. If the sandstone were 10m thick then half the bed would be logged at the sandstone ROP and half at the shale ROP. Variations in logging speed affects resolution so that it might look, just from the gamma curve, that there is some variation in lithology which may not be the case. In some Geosteering applications ROP is controlled to facilitate data integrity so this will also have to be taken into consideration when interpreting LWD data. Baker Hughes INTEQ, with their OnTrak MWD system have an azimuthal gamma ray tool. Which can be used for making estimations of apparent formation dip. The tool has two detectors that are oriented 180° apart with the same sensor depth offset. Any depth differences are a result of the relationship between the well inclination and bed dip.

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Petrophysics

MWD Overview

Figure 9: MWD Gamma Ray Logging Speed Response

Resistivity Logs Electrical resistance is the ability of a material to impede the flow of an electrical signal. The formation matrix materials, or grains,are normally thought of as being insulators and therefore do not contribute to formation conductivity. The main electrical conductor in the formation is saline water which is mostly confined to the pore space. Hydrocarbons, oil and gas, are also deemed to be electrical insulators. Hence, low formation resistivity is usually indicative of salty water filled porosity whilst high formation resistivity can either indicate the presence of hydrocarbons or that the rock has low porosity. Resistivity tools are, therefore, fundamental in the search for sub-surface hydrocarbons. Resistivity logs can also indicate the presence of permeability within the formation, whether water or hydrocarbon filled. This requires an array of curves with

Petrophysics

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MWD Overview different depths of investigation which will indicate variations in fluid type away from the borehole. When drilling high angle or horizontal wells resistivity information becomes important in geosteering applications. Deep reading resistivity tools can indicate variations in lithology or fluid type before the boundary is crossed and the well can be steered away. This is most useful when azimuthal tools are used which can indicate whether the tool is looking up, down, left or right. A major benefit of MWD resistivity over wireline data is the formation exposure time. Wireline logs may be run days or even weeks after the section has been drilled, resulting in significant invasion of permeable zones by mud filtrate. This invasion makes log interpretation difficult and requires resistivity tools with deep depths of investigation to identify hydrocarbon bearing zones. MWD tools log within minutes of the section being drilled when invasion might be thought of as minimal, thus enhancing the interpretation process. Short Normal Resistivity During the late seventies, MWD companies looked for a resistivity measurement which could be easily made using existing technology. The 16-inch short normal measurement was chosen as it was thought to have very useful applications for pore pressure evaluation in the Gulf of Mexico. The short normal (SNR) tool has a typical operating range from 0.2 to 50 ohm-m and provides a basic resistivity measurement in water based fluids where formation resistivity is close to mud resistivity.

Meter Generator N

B

Spacing

M

O

A

Figure 10: Short Normal Theory

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Petrophysics

MWD Overview Focused Current Resistivity (FCR) The laterolog technique, commonly used in wireline logging, provided the basis for improvements to short normal MWD. In 1987, Exploration Logging (EXLOG) introduced a laterolog-style MWD tool. This Focused Current Resistivity (FCR) tool added focusing current electrodes above and below the measurement electrode to force the measurement current deeper into the formation. The focused current resistivity (FCR) sensor was designed to perform optimally in salt saturated muds, providing excellent thin bed resolution and improved response in formations where Rt is in excess of 200 ohm-m

Figure 11: Electrode Type Resistivity Tools Measurement Principle The FCR sensor uses the same measurement principle as the guard or laterolog tool of the wireline industry. The sensor utilizes three current emitting electrodes: two focusing and one measurement current electrode. Current is focused into the formation by forcing the voltage of both the focusing electrodes and the measurement electrode to have the same potential. A disc of investigating current perpendicular to the axis of the tool, is focused horizontally into the formation. The current from the

Petrophysics

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MWD Overview focusing electrodes prevents the measurement current, from flowing vertically in the borehole. Like the SNR the FCR is a series measuring device. The current disc passes through the borehole fluid, then into the formation. Both output voltage and current from the measurement electrode are measured. Formation resistivity is calculated from Ohms's Law using the current and voltage of the measurement electrode. The resistivity is converted to an apparent formation resistivity using the “K” factor of the tool. Toroidal Resistivity Toroidal Resistivity is offered commercially by Halliburton and Anadrill/Schlumberger also use the toroidal principle in the RAB tool. The toroidal resistivity tool is based on a proposal by JJ Arps. The tool utilizes the collar as an electrode to provide two resistivity measurements: a focused lateral resistivity measurement and a trend resistivity at the drill bit. The tool utilizes four toroidal coils covered and protected by insulating shells. A voltage applied from the drive toroid induces an alternating current in the drillstring, which is reversed in polarity about the drive toroid. Current leaving the drillstring flows through the annulus and formation and returns to the drillstring at a point where the polarity is opposite. Essentially, induction drives a current along the collar and two sets of receivers measure this current. Tool performance in lateral mode depends on the length of BHA below the receivers. As the distance from the lower toroid to the bottom of the hole increases, the bit measurement becomes less distinctive, and at lengths of 20 feet or more the bit resistivity almost ceases to respond to changes in formation resistivity (K factor is therefore BHA dependent). With oil based muds an axial bit measurement is still possible, because of the contact of

1-16

Petrophysics

MWD Overview the drill bit with the formation (interstitial water). However, it should be noted that axial bit measurement will not be possible with the bit off bottom.

Figure 12: Schlumberger RAB Tool Electromagnetic Wave Propagation Resistivity Electromagnetic waves propagated through the formation are affected by resistivity variations rather than the nature of the rock. The waves are slowed as the conductivity of the formation increases causing the amplitude of the wave to become attenuated. In order to maintain the same frequency the wavelength changes. Measurement of amplitude attenuation and phase shift (difference) as seen by a pair of receivers some distance from the transmitter enables the formation resistivity to be calculated.

Petrophysics

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MWD Overview The standard WPR tool used by most vendors is a 2-Mhz device that provides two resistivity measurements at different depths of investigation. For example, the Baker Hughes INTEQ tool contains two receiving antennas which are spaced 27.5 and 34.5 inches (69.85 and 87.63 cm) from the single transmitting antenna.

Figure 13: Electromagnetic Wave Propagation Phase Difference Measurement

The DPR sensor measures these signal changes by detecting the difference in phase, or phase shift, between the two receivers which are spaced 7 inches (177 mm) apart. This receiver spacing is only a small fraction of a wavelength in high resistivity formations, resulting in small phase differences in high resistivity formations. Conversely, larger phase differences occur in low resistivity formations. Amplitude Ratio Measurement

The transmitted DPR signal is dramatically attenuated (signal amplitude decreases) as it propagates through a conductive formation. The signal is attenuated very quickly in low resistivity formations, and to a lesser extent in high resistivity formations. By comparing the signal amplitude at the near and far receivers, the DPR sensor measures the attenuation that occurs between the two receivers. This attenuation or amplitude ratio measurement, like the phase difference measurement, is subsequently converted to resistivity.

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Petrophysics

MWD Overview Depth of Investigation By measuring both the phase difference and attenuation between the two receivers, the DPR sensor provides two resistivity measurements with different depths of investigation: a shallow phase difference and a deep attenuation measurement. The lines of constant amplitude around the transmitter are very wide, resulting in the depth of investigation of the amplitude ratio measurement being greater than the transmitter to receiver spacing, (namely 27.5"). In contrast, the lines of constant phase form a sphere radiating from the transmitter. This results in a depth of investigation approximately equal to the transmitter to receiver spacing. Depth of investigation (DOI, expressed as a diameter) for propagation resistivity MWD measurements is strongly dependent on and positively related to formation resistivity. For the DPR phase difference measurement, depth of investigation ranges from 23 inches in low resistivity formations to over 50 inches in higher resistivities. For the amplitude ratio measurement, the DOI range is roughly 40 to 60 inches, depending on resistivity.

Figure 14: 2MHz response

Petrophysics

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MWD Overview

Figure 15: 400 kHz response

Figure 16: EWR Log

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Petrophysics

MWD Overview Borehole Corrections Borehole size and mud resistivity will affect the response and need to be corrected. Dialetric factors, (the ability of the formation to store an electrical charge) are often responsible for variations in response, particularly separation of the amplitude and phase curves. In thinly bedded reservoirs, resistivity measurements may be adversely affected by overlying and underlying lithologies. Tool eccentricity and formation invasion can also be corrected.

Current Systems Halliburton, under its Sperry Sun product line has a tool called the EWRPhase4™ which has four radio-frequency transmitters and a pair of receivers. By measuring both the phase shift and the attenuation for each of the four transmitter-receiver spacings, eight different resistivity curves with differing depths of investigation can be provided. These are referred to as Extra Shallow, Shallow, Medium and Deep giving depths of investigation from 19” to 141” depending on the resistivity of the formation being investigated.

Figure 17: Sperry Sun EWR Phase4 Schlumberger and Baker Hughes INTEQ also have tools which produce electromagnetic waves at 400kHz. Amplitude Attenuation and Phase Difference resistivities are again computed but the 400kHz wave produces deeper investigation than the corresponding 2Mhz curves. The original Dual Propagation (DPR) devices have also been supplemented, as with the Sperry Sun tool, with additional transmitters and receivers to produce multiple wave propagation tools (MPR). The Baker Hughes INTEQ MPR tool, for example, is characterized by a compensated antenna design. A pair of receiving antennas spaced 8 inches apart are bounded above and below by a pair of

Petrophysics

1-21

MWD Overview transmitting antennas, which are spaced 23 and 35 inches from the measure point (halfway between the receiving antennas). Measurements are taken in both directions (transmitting signal above and below) and averaged to cancel any borehole effects or drifting of electronics (drifting electronics are typically caused by increasing temperature and pressure downhole and is a problem which plagues single transmitter or uncompensated designs). This produces Long Spacing and Short Spacing resistivity measurements derived from Amplitude Attenuation and Phase Difference responses from both the 2Mhz and 400kHZ wave forms. This gives a total of eight resistivity curves of varying depths of investigation and vertical resolution. Data processing of all this information can be done to produce a set of resistivity curves of nominally set depths of investigation at 10”, 20” 35” and 60” Generally speaking, amplitude attenuation resistivity gives deeper depth of investigation but poorer vertical resolution than phase Difference derived resistivity. Generally, electromagnetic wave propagation resistivity has the following characteristics: • Tools measure more accurately in conductive media. • Improved vertical resolution in conductive media. • Depth of investigation increases with increasing formation resistivity. • Depth of investigation is deeper for the 400 kHz resistivities than the 2 MHz resistivities. • Depth of investigation for attenuation resistivities is deeper than phase difference resistivities. • Depth of investigation for long spaced resistivities is deeper than for short spaced resistivities. • Depth of investigation for ratio and difference resistivities is deeper than for raw measurements. • Depth of investigation order is as follows: ⇒ 400 kHz Rat > 2 MHz Rat > 400 kHz Rpd > 2 MHz Rpd ⇒ long spaced > short spaced ⇒ attenuation > far amplitude > near amplitude ⇒ phase difference > far phase > near phase

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Petrophysics

MWD Overview • Vertical resolution is better for 2 MHz resistivities than for 400 kHz resistivities. • Vertical resolution is better for phase difference resistivities than attenuation resistivities. • Vertical resolution is better for differences and ratios than for raw measurements. Typically wireline resistivity data is used to identify hydrocarbons, estimate Rt (true formation resistivity) for saturation calculations and model invasion profiles (separation of multi-depth of investigation tools). This is still possible with MPR measurement while drilling devices although estimates of Rt are possibly less accurate and invasion is almost certainly less developed. One of the main benefits of MWD resistivity is its assistance in Geosteering applications. Modelling the resistivity response can help in target finding and in drilling the reservoir, providing adequate offset data is available or a pilot hole is drilled before any high angle sidetracks are drilled. When drilling shallow dipping beds at a high borehole angles, or even horizontally, MWD resistivity tools will pick out bed boundaries and fluid contacts according to the depth of investigation of the tools. Deeper investigation will allow earlier confirmation of bed boundaries or fluid contacts and result in lower doglegs when drilling away from undesirable features.

Figure 18: Distance to bed confirmation

Petrophysics

1-23

MWD Overview Formation Anisotropy Shale and thinly laminated sand-shale sequences can exhibit anisotropy. This results in one resistivity horizontally, Rh (assuming a flat lying formation), and another generally higher resistivity vertically, Rv. Whereas a propagation resistivity or induction tool in a vertical hole would detect the horizontal resistivity, any well deviated from the normal to the bedding plane (the extreme case is a horizontal well through flat lying formations) would measure an average of the horizontal and vertical resistivities. Hence, anisotropy effects are highly dependent on the relative dip between the formation and the borehole. Generally, as relative dip increases from 45 to 90 degrees anisotropy effects in anisotropic formations range from small to significant.

Figure 19: Vertical Well Given sufficient relative dip, anisotropy almost always causes the phase difference based resistivity to be greater than the attenuation based resistivity and both will be greater than Rh and less than Rv. Also, anisotropy will cause higher frequency measurements (2 MHz) to have greater resistivity values than equivalent low frequency measurements (400 kHz). Both of the above described effects produce a pattern that is similar to resistive invasion i.e. Rxo greater than Rt. However, an anisotropy effect which is not consistent with resistive invasion is

1-24

Petrophysics

MWD Overview long spacing measurements will show greater resistivity than equivalent short spacing measurements.

Figure 20: Horizontal Well

Neutron Porosity - Density Measurements MWD measurements of porosity and density came along some time after gamma ray and resistivity data were included. The tools function in much the same way as their wireline log equivalents but with a little more data processing required to overcome borehole and tool rotation/eccentricity effects.

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1-25

MWD Overview Neutron Porosity

Figure 21: Neutron Porosity Tool Most tools use a chemical source (americium-beryllium) and a lithium scintillation detector to measure the passage of emitted neutron particles through the formation. When a neutron is captured, the resulting lithium-6 nucleus is unstable and decays to triton and an alpha particle with a combined kinetic energy of 4.78 MeV. These high energy particles ionize the glass matrix and produce light flashes or scintillations. A photomultiplier tube converts the scintillations into electrical pulses which are proportional to the energy of the scintillation. They are slowed down from energies of several million electron volts (e.g. 4.5 MeV) to a thermal energy of 0.025 eV (electron volts) through a process called elastic collision (they are scattered from the nuclei). The material most responsible for this slowing process is Hydrogen since this has a mass most equivalent to that of the emitted neutrons. In effect, therefore, the tool is measuring the hydrogen content, or index, of the formation; since most hydrogen is present in ore fluids (gas, oil, water) then the hydrogen index is converted directly into a

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Petrophysics

MWD Overview porosity value. API calibration is done with respect to the original test calibration borehole at the University of Houston but with specially constructed calibration rigs. Most Neutron Porosity logs are therefore output in Limestone porosity units, although this doesn’t have to be the case.

Formation Density Again the MWD formation density tool works in a similar manner to its wireline equivalent. High energy gamma rays are emitted from a chemical source (Caesium-137) and are slowed by and counts measured by near and far detectors (to correct for mud cake effects). The high energy gamma rays are initially slowed by Compton Scattering type interactions where the incident gamma ray loses some, but not all, its energy on particle collision and is deflected to move off and be subject to more collisions. Sodium Iodide scintillation detectors count the incoming gamma rays. At energy levels below 100 keV the dominant gamma interaction process is photoelectric absorption. In this process, the incident gamma ray is absorbed and transfers its energy to a bound electron. A Pe measurement clearly distinguishes between different elements within the formation, making it possible to discriminate between sandstone (Pe=1.8), dolomite (Pe=3.1), and limestone (Pe=5.1). Thus, this is an important mechanism by which the density tool is made sensitive to the lithology of the formation.

Figure 22: MWD Density Tool

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MWD Overview

Figure 23: Stand-off Binning

Sonic Logs MWD sonic logs have only been available relatively recently but are useful in providing real-time data for identifying compaction trends for pore pressure analysis and provide information about over-pressured zones. A synthetic seismogram can be constructed to tie into the surface seismic section along the wellbore trajectory, although this is not usually done in real-time. MWD sonic tools work in a similar manner to wireline tools. An acoustic source is linked to an array of (usually) four receivers with a spacing similar to that used in long-spaced wireline tools. This allows for greater time separation between compressional, shear (in fast formations) and fluid modes and the ability to measure beyond formation damage and invasion.

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Petrophysics

MWD Overview

Figure 24: Sperry Sun BAT Tool

Pressure While Drilling Two types of Pressure While Drilling MWD tools are now available. For a number of years tools with external pressure transducers have been able to measure downhole annular pressure in order to derive circulating (ECD) and static (ESD) mud pressure information which are both crucial in drilling performance and operational safety.This information can be used in real time to optimize performance and minimize risk by identifying hole cleaning, borehole stability and well control issues. During 2004/2005 formation pressure measuring tools have also become available which supplement traditional drillpipe and wireline conveyed pressure testing tools. In permeable formations accurate measurements of pore pressure can be made to help optimize drilling performance and safety and to help calibrate any indirect estimates of formation pressure that have been made. They can also help identify formation fluids and contacts by obtaining pressure gradient information.

Drilling Mechanics Vibration analysis and downhole weight on bit and torque measurements can also be obtained in order to optimize drilling performance and to reduce possible drillstring damage. Downhole longitudinal and lateral strain gauges and shock measurements provide the data to help identify such things as ledges, high friction coefficients, BHA whirl and stick-slip effects.

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MWD Overview

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Petrophysics

LWD Imaging Logs Overview Modern LWD tools can provide detailed borehole and formation images using high resolution, azimuthal resistivity, density and acoustic data. The images provide two-dimensional geological, petrophysical and geomechanical information to help optimize geosteering and drilling performance. Azimuthal measurements are taken as the borehole rotates. Linked to a directional sensor this provides full 360° coverage. A graduated colour scale is assigned to the data and the images are oriented by tool magnetometers. The 360° data are plotted on two-dimensional paper by unwrapping the image from the top of the hole when drilling high angle/horizontal beds. The log track therefore has the bottom of the hole in the centre, with left to the right and right to the left centre. The right and left extremes of the track correspond to the top of the hole. The graduated colour scale usually has low resistivities shown by dark colours and high resistivities shown by light colours. When drilling the reservoir this shows shales as dark and hydrocarbon bearing reservoir rocks as light. Similarly, low densities are shown as dark colours and high densities as light colours.

Figure 1: Imaging Log Overview

Petrophysics

2-1

LWD Imaging Logs Using LWD imaging tools when drilling a borehole at an angle to dipping beds the bed boundaries will intersect the borehole at different levels when looking in different azimuthal directions. When 360° data is opened up and plotted in twodimensions the dipping bed intersecting the borehole will show as a sinusoidal curve. The amplitude of the curve will show the apparent (relative) dip of the beds and the curves will point up or down the log depending on whether the borehole is drilling up or down section. Drilling at a high angle to the bedding will give horizontal images and drilling parallel to the bedding will give parallel images. Additionally, fractures, borehole breakout and secondary porosity features may be identified from the images. Conductive drilling fluid filled fractures and breakout will show as dark features while cemented fractures will show as light coloured features.

Figure 2: Schlumberger Vision Density Image

Resistivity Images The Schlumberger GeoVISION resistivity tool contains three one-inch buttons measuring azimuthal resistivity. This compares with the wireline FMI tool which has 192 buttons. The sensor spacing between the three buttons produces different depths of investigation and images are available from each spacing. The images can be used to identify thin beds, invasion, structural dip and stratigraphic features.

2-2

Petrophysics

LWD Imaging Logs Density Images Density and photoelectric effect tools can provide images in non-conductive drilling fluids and are available for hole sizes down to 5¾”. They are usually measured and plotted by quadrant (up, down, left, right) or, in the case of the Schlumberger ADNVision tool, in 16 sectors around the borehole. They provide enough detail to identify structural dip, faults and large scale stratigraphic features. Information is provided about drilling up or down section and modelled density responses can be used to identify bed boundaries or fluid contacts.

Figure 3: Schlumberger ADN Tool

Petrophysics

2-3

LWD Imaging Logs

Figure 4: Schlumberger ADN Log

Wellbore Stability Real time LWD measurements, including acoustic caliper, and cuttings, cavings analysis and drilling fluid solids content can be used to help interpret the mechanical stability of the borehole. High ECD values may cause mud induced features such as fracturing whilst anisotropic tectonic stress may cause borehole breakout along certain azimuths. This data together with pore pressure and kick tolerance information is important in optimizing drilling fluid pressures and hydraulics to maximise drilling effciency and safety.

2-4

Petrophysics

LWD Imaging Logs

Figure 5: Schlumberger GeoVISION Borehole Breakout

Geosteering Applications Imaging logs can be used for a variety of geosteering applications such as the identification of: • Lithological Boundaries • Fluid Contacts • Borehole - Bedding angles • Drilling attitude: up section or down section • Faults

Petrophysics

2-5

LWD Imaging Logs

Figure 6: Drilling up or down section

Figure 7: Geosteering Applications

2-6

Petrophysics

LWD Imaging Logs

Figure 8: Fault Identification

Petrophysics

2-7

LWD Imaging Logs

Petrophysics

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Geosteering Techniques Introduction

Geosteering • Those activities designed to place the wellbore in a pre-determined location • Location being defined by both its spatial coordinates, in three dimensions, & by its position in the geological column. • Proper geosteering will optimise wellbore placement in the productive reservoir, maximising both drilling efficiency & hydrocarbon production.

1

Copyright Stag Geological Services Ltd. 2006

Geosteering Techniques

Contour Map with Geosteering Well Prospect M-05

surface location

M-18

M-37 tal on riz ho

M-13


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Fence Plot for Geosteering Well Prospect

M-37

SP

Resistivity x500

M-18 Resistivity

SP M-05 SP

Resistivity x600

x600

sand thickness 24 ft

sand thickness 20 ft SP

M-13 Resistivity x700



3



True Scale Section Plot and Section Schematic 6800 gas

6900 original plan

7000

actual well

2000

1500

2500

3000

3500

4000

4500

gas oil water 5000

Vertical section (AZI = 325) (ft) 1500

2000

2500

3000

3500

4000

4500

5000

6920

N2L

Pilot

Original Plan

6940

b

c

Shale

N3 N2L

6960 6980

Actual path

Modified Plan

N3

a

7000

Faults

N2L 7020

N3 OWC

7040 Copyright Stag Geological Services Ltd. 2006

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Introduction

• Rate of Penetration (ROP) • Cuttings Evaluation • Oil Show Evaluation • Gas Ratio Analysis • Logging While Drilling (LWD) Gamma Ray (GR) Resistivity Density-Neutron Porosity • Biostratigraphy • Chemostratigraphy Copyright Stag Geological Services Ltd. 2006

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Geosteering Techniques Rate of Penetration


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• Variations in ROP may indicate lithology changes

• Variations in ROP may indicate reservoir heterogeneity

• Variations in ROP may indicate faults

7



ROP is the first indication we have that changes have occurred downhole: • Before a sample reaches the surface • or LWD tools reach the zone (unless RAB for example)

ROP will indicate immediately if the well has: • Left the reservoir • Crossed a fault Copyright Stag Geological Services Ltd. 2006

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ROP must be consistent throughout the reservoir • Consistency will be obscured if sliding is needed to alter the trajectory • Drilling parameters such as WOB, RPM & pump pressure must be constant • If a reservoir consistently drills fast, then lower limits can be applied. For example if the well has been drilling at 500 ft/hr average then anything below 350 ft/hr will indicate that something has changed. However if it is a particularly tight reservoir which depends primarily on fractures for its permeability, then an average ROP will be difficult to determine. Here a good ROP may be 80 ft/hr, but a zone at 30 ft/hr may have a high fracture density.

• It is not always clear cut & depends on the reservoir being drilled.

9



ERD / Horizontal Well Issues:

Rate of Penetration

• The weight indicator does not always reflect the exact weight being applied to the bit • But it is clear from the addition of extra weight that the WOB does have an effect. • Often in sand reservoirs with high torque it is difficult to get all the weight to the bit & as a result the ROP decreases. • Short wiper trips to reduce torque will often help to increase ROP.


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ERD / Horizontal Well Issues (contd.):

Rate of Penetration

•Look at the ROP to see if there is a correlation with changes in shows • ROP will reflect visible porosity (among other variables!). Obviously the faster the formation drills the more porous it is. In friable grainstones or loose sands the ROP will be very fast & using this as a first line guide efforts can be made to keep the well path within this zone • Correlation with LWD will invariably show that high ROP’s will occur in the optimum reservoir. • Exceptions to this will be in lithologies with low matrix or granular porosity but a high fracture density 11



ERD / Horizontal Well Issues (contd.):

Rate of Penetration

• Regular plots of the ROP trace should be provided by the mudloggers • A certain pattern in the ROP from the pilot hole will provide a valuable tool in recognition of certain zones within the reservoir & can be combined with biostratigraphy & shows to give a type zone. This is very important in fault recognition • Sometimes the ROP observed in the pilot hole may be higher in the horizontal hole simply because the bit has found the optimum ‘drillability’ layer. A vertical well will probably miss this


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Very porous reservoir such as a loose Tertiary sand: • WOB will decrease and the ROP increase. • There will also be a change in torque.

Rate of Penetration

In the event of having to orient a mud motor by sliding the RPM will be reduced and the ROP will drop. These factors play an important part in geosteering the well. It is therefore important to be aware of the intervals where sliding takes place. In a very porous reservoir the ROP will still be relatively high in a sliding mode. Increases in drag will increase the torque & ROP’s will be lower as the well path increases. However after a wiper trip or the addition of a lubricant ROPs will more properly reflect the reservoir type. 13


Geosteering Techniques Oil Show Evaluation

• Offset logs or pilot hole data will provide information on type of shows to be expected in the reservoir • First determine preliminary layering based on shows. This could be colour of natural cut, intensity, rate of cut. Natural cut is the best method of show identification. • It is advisable where possible to observe example cuttings or core data. If these are not available a thorough study of a type example of show variation should be attempted. This will involve detailed notes on sample descriptions from mud logs or final well reports.


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• For speed of access to the information so that decisions can quickly be made, it is important to take natural cuts first This is the new wet technique (Simpson 1991) • Place a specified amount of wet washed sample, usually 3cc and cover with twice the volume with solvent. • This is then agitated for a minute by shaking & then siphoned into a second test tube. The colour of the cut will then be readily apparent. • It is important to keep a reference set of samples in a test tube whilst drilling. 15



Oil staining is also important • In the optimum reservoir this might appear as very dark amber tan • Immediately outside the optimum the stain may decrease to a medium tan • For this reason it is very important to keep a reference set of samples whilst drilling in order to observe local changes in the oil stain • When the well bore leaves the optimum zone an immediate change in colour will normally be observed • If the well is bouncing across the boundary, the staining may vary little; this is why all other methods are important Copyright Stag Geological Services Ltd. 2006

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• The speed of the fluorescence cut will act as a back up indicator • It will nearly always be slower in tighter formations with low ROP & faster in more porous, higher ROP sections • In optimum areas the cut may occur instantly & generally diffuse indicating good porosity • In areas with less porosity the cut may be streaming; even less porous formations may yield the cut over a period of minutes in a slow diffuse manner. • The behaviour of the cuts will need to be examined in detail to determine how they behave in the optimum part of the reservoir. 17



• In optimum reservoirs the oil residue left in the spot tray after the solvent has evaporated will be a more rich & deeper brown colour • In areas approaching the water zone this will appear as a weaker & thinner pale brown rim • In tighter areas within the oil column, say immediately above the optimum zone the oil residue will normally be a rich brown but very thin.


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Geosteering Techniques Gas Ratio Analysis

Gas Ratio Analysis techniques are based on the theory that an increasing hydrocarbon fluid density in the reservoir will manifest itself at the surface as an increasing gas density Thus, while a quantitative analysis of surface gas to reservoir fluid is not possible, a qualitative analysis is the most common method used today was developed by Baker Hughes INTEQ, & comprises: • Gas Wetness Ratio

• Light-Heavy Ratio • Oil Character Qualifier


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Gas Ratio Analysis

Gas Ratio Analysis

Gas Wetness Ratio (GWR, Wh)

C2 + C3 + C 4 + C5 ×100 C1 + C2 + C3 + C4 + C5 GWR 0.5 0.5 - 17.5 17.5 -40 > 40

Fluid Character Very Dry Gas Gas, increasing density Oil, increasing density Residual Oil

Light-Heavy Ratio (LHR, Bh)

C1 + C2 C3 + C4 + C5 Oil Character Qualifier (OCQ, Ch)

iC4 + nC4 + C5 C3

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Inclinometer position Motor downhole motor

MWD Directional Sensor Typical 15 - 20 m

• Directional- and LWD sensors 15-20 meters behind the bit. • Drilling efficiently at Troll West with “blind zones” (inclination, GR and Resistivity) is not possible

NaviGator

Inclination

NBI 4.1 m Directional Sensor 18 m

• TELECO patent from 1988 – signal transmission from sensor sub to MWD through cable in stator housing • Geosteering contracted in 1993, instrumented motor supplied to G-4AH – August 1994. • NaviGator geosteering motor became the standard drilling tool at Troll and other Hydro operations • TVD control requirements were met from the first well • The Thruster/NaviGator combination increased the drillable length of horizontal section from 1800m to 2300 m 25


Geosteering Techniques LWD (Gamma Ray)

Gamma Ray tools used for: • Geological Correlation • Bed Boundaries • Geosteering


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Geosteering Techniques Logging While Drilling (Gamma Ray)

Oriented Gamma Ray • The Baker Hughes INTEQ “OnTrak” MWD System provides an Oriented Gamma measurement that can be used to calculate apparent dip. • This tool is integral to the revised Autotrak G3 tool • The tool has two detectors that are oriented 180º apart with the same sensor depth offset • Any depth differences are a result of the relationship between the well inclination & bed dip

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Bed dip calculated from measured depth difference between the two GR values

Logging While Drilling (Gamma Ray)

Typical Sensor Specifications: Sensor Type:

Scintillation

Measurement:

API GR

Range: Accuracy: API

0-250 API ±2.5 API @100 & ROP =

60ft/hr Vertical Resolution: Copyright Stag Geological Services Ltd. 2006

6 ins (15.3cm) 28

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Geosteering Techniques Resistivity Logs

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Baker Hughes INTEQ MPR


Logging While Drilling (Resistivity)

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Distance to Contact

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Projecting Distance to Contact 3 ft depth of investigation at 2 deg means 85 ft look ahead of the bit?

Inductive Propergation Shallow Resistivity

Pay

Azimuthal electrical resistivity At-the-bit electrical resistivity

f

Inductive propagation deep resistivity


Drilling dis

tance to co

ntact

Non-Pay

36 pp31

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Distance to Contact


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Distance to Contact


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Geosteering Techniques vertical well

vertical well

low res shale

high res oil/gas

very low res water Inductive devices read in ground loops perpendicular to the tool. The measurement effectively sees each layer.

Electrical devices read in current paths parallel to the tool. The measurement sees each layer depending on focusing. 39



horizontal wells

low res shale

high res oil/gas

very low res water Inductive device loops are “opened” by the higher resistivity layers and read high. Copyright Stag Geological Services Ltd. 2006

Electrical devices “short circuit” through the lower resistivity layers and read low. 40

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Recovery Distance • Angle of incidence • Bit-to-sensor distance • Maximum permissible curve rates • Anticipated changes in geology


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Recovery Distance Terms


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Geosteering Well Example


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Azimuthal Measurements


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Geosteering Well Example: Azimuthal Test Results 6 5 4 Resistivity 3 (ohm-m) 2 1 0 50

Azimuthal Button Resistivity

0 High Side 90

-90 Low Side

Azimuthal Focused Gamma Ray

180

40 30 Gamma ray 20 (gapi) 10 0 Depth 9083

Depth 9145

Depth 9173 45 pp46


Geosteering Techniques Geology Structure Interpretation Before AZI Tests

Vertical section (AZI=330) (ft) 1600 2000

1200 7250

2400

True vertical depth (ft)

D14

2800 D11

Current depth = 9160

7300 GR

RES

7350 Resistivity data


Vertical section (AZI=330) (ft) 1600 2000 2400

D14

True vertical depth (ft)

Geology Structure Interpretation After AZI Tests

RES

Gamma ray

7400

1200 7250

GR

2800

D11 Current depth = 9160

7300

GR RES 7350

Resistivity data 7400

Gamma ray

GR RES

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Geosteering Techniques BHI DeepTrak™ MPR Resistivity


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Geosteering Techniques Logging While Drilling (Imaging Logs)


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Geosteering Techniques Logging While Drilling (Density/Porosity)


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Schlumberger ADN BHA and Image Log


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Geosteering Techniques Schlumberger ADN Image Log


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Geosteering Techniques Schlumberger Vision Tools


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Schlumberger GVR Tool


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Geosteering Techniques Schlumberger Geovision Resistivity Image (GVR)


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Geosteering Techniques Schlumberger Geovision RAB Image


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Geosteering Techniques Schlumberger WellEye™


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Geosteering Techniques Schlumberger WellEye™ Hole Shape


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Geosteering Techniques Anadrill Vision 675


Logging While Drilling (Density/Porosity)

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Geosteering Techniques MWD Operations: Tool Face Angle showing good directional control

LAST SURVEY

UP

++ +

90.6 inclination

265.4

LAST TOOL FACE 1.4 R

+

+ + ++ ++ + ++

azimuth

LEFT

degrees

RIGHT

1.5û BH motor configuration

DOWN

Tool Face Display 77 pp27


Geosteering Techniques MWD Operations: Tool Face Angle showing poor directional control

LAST SURVEY

UP

-82.4L

90.6

degrees

inclination

265.4 azimuth

LEFT

LAST TOOL FACE

+ + + + + + ++ + + + + +

RIGHT

1.5û BH motor configuration

DOWN

Tool Face Display Copyright Stag Geological Services Ltd. 2006

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Geosteering Tool Surveying Operations What it takes to maintain trajectory control within +/- 18” MWD tool TD at previous connection 6423

CDR tool O

current TD 6454

MWD INCL MWD AZI GeoSteering Tool

"Official Survey" O Bit INCL

"GST Old"

O Bit INCL

"GST New" 79



Model Sketch • Create formation description from offset wells (layer cakes) • Model tool response through formation along proposed trajectory • Create look-up table for wellsite monitoring • Tool response modeled for changes in formation and/or trajectory


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Geosteering Screen with Density Image

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TVD control in the reservoir 15 7 6 15 7 7

Motor

G-3 H

15 7 8 15 7 9 15 8 0 15 8 1 15 8 2 15 8 3 15 8 4 15 8 5 15 8 6 1 70 0

1 90 0

21 0 0

2 30 0

2 50 0

2 70 0

29 0 0

3 1 00

3 30 0

35 0 0

3 7 00

3 90 0

41 0 0

4 3 00

1 580 1 581

G-4 AH

1 582 1 583

Instrumented motor

1 584 1 585 1 586 1 587 1 588 1 589 1 590 17 00

190 0

2 10 0

23 00

2 500

2 700

290 0

3 100

33 00

350 0

37 00

39 00

4 100

43 00

1574

Rotary Steerable System

1575

S-13 AH

1576 1577 1578 1579 1580 1581 1582 1583 1584 1700

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2100


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Geosteering Techniques Schlumberger Periscope™ Deep EWR Resistivity


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05/10/2005

Geosteering Strategies Geosteering Geosteering •

Fundamentals

•

Strategy

•

Tools

•

Roles & Responsibilities

•

Communications

1


Geosteering Strategies Geosteering - Fundamentals Geosteered or Geometric? •

If the reservoir is a massive sand, geometric wells are likely to be adequate & the cheapest option

•

For interbedded reservoirs, an element of geosteering (perhaps just landing the well) is probably required

•

Drillers prefer geometric wells

How? Biostratigraphy Suitable fossils & well developed zonation scheme Lithostratigraphy Important if there are permeability barriers - need to be in the correct sand for sweep efficiency Lithology May only need to be good reservoir, but it is necessary to know where you are to make informed decisions Copyright Stag Geological Services Ltd. 2005

2

1

05/10/2005

Geosteering Strategies Geosteering - Strategy Strategy •Needs to be workable & clear •Detailed drill on paper will help to prepare team How unique are intra reservoir markers? How good is the geological model? How good is the seismic? What are you going to do if (when) you get lost? How are you going to react to raised water? Alternative targets? What are you going to do if directional control is lost? •Contingencies Case & cement for unexpected water Sidetrack - open hole or mechanical

3


Geosteering Strategies

Strategy – contd.

Geosteering Strategy

Vertical Constraints •Top of reservoir, Zone of Interest •Base of reservoir, Zone of Interest •Stand-off (SO) from OWC, GOC •Make sure that you understand what the real SO is - push Reservoir Engineers for their minimum SO at various positions in the well. This can avoid unnecessary steering.


4

2

05/10/2005

Geosteering Strategies Geosteering - Tools Tools For finding apparent bed dip •Correlation of repeated sections •Azimuthal tools - logging wipes, time consuming •Apparent vertical thickness - in areas with consistent unit thickness •Seismic may help Correlation •Need to be able to produce True Stratigraphic Thickness (TST) logs at the wellsite

5


Geosteering Strategies Geosteering - Tools Cross Section & Decision Tree ¾ When used in conjunction with a cross-section it helps to communicate the Geosteering Strategy & the Well Objectives to the entire team. ¾ Provides a view of the well progress & flags upcoming potential decision points ¾

Should be adapted to the requirements of the job


6

3

05/10/2005

Geosteering Strategies Geosteering - Tools

Geosteering Decision Trees Vertical Section (ft) Plus x ft 0

50

100

150

200

250

300

0 Depth (ft) Plus y ft

Well Objectives

20 40 60 80 100 120 140

‘Landing the Well’ Decision Tree

‘Drilling the Horizontal Section’ Decision Tree

‘Calling TD’ Decision Tree

Decision Trees do not have the answers, but they can help structure structure the decision making process. 7


Geosteering Strategies Trip to change BHA, this may add another additional trip

Target formation shallow to plan?

Drill pre-reservoir section

No

Decision Tree: Landing the Well Deep- Adjust trajectory?

No

No

Yes

No

Yes

Able to achieve planned build rate?

Vertical Section (ft) Plus x ft Adjust trajectory?

0

No

No

Yes Yes

Continue drilling

Yes

Continue on plan


TAKE TIME OUT Trip to change BHA Reconsider target options Plug back Able to Increase build rate?

No

Agree new stratigraphically deeper target

Yes

Adjust trajectory to land in planned target

50

100

150

0

Yes

Monitor correlation

Correlation on plan?

Able to decrease build rate?

D e p th ( ft) P lu s y ft

Accept landing position?

Yes

20 40 60 80 100 120 140

No

Agree new stratigraphically shallower target

SOME CONSIDERATIONS Sand distribution- massive, thin bedded Water movement- k barriers Avoid sump at heel of well- coning, slugging

Adjust trajectory to land in planned target Continuously monitor correlation & trajectory

LAND WELL

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4

05/10/2005

Geosteering Strategies Decision Tree: the Horizontal Section

Vertical Section (ft) Plus x ft 0

50

100

150

200

250

300

0

Depth (ft) Plus y ft

20 40

SOME CONSIDERATIONS Sand distribution- massive, thin bedded Water movement- k barriers Continuously assess status with respect to Well Objectives Facies development TAKE TIME OUT Wrong Target sand not developed Direction? Run out of section

60 80 100 120

No

140

Target sandstone with good Phi & K?

No

Yes Yes Know Target stratigraphic unit above min. position? standoff?

Examine azimuthal data, TST sections, seismic data

Yes

No Related to local faulting and running casing? Yes

Yes Continue drilling horizontally

Water from isolated high perm zone

No

Is there Room To Reverse direction?

Assess data & make best estimate of position w.r.t. target sand

No

No Low Sw?

Yes

Adjust trajectory to move into target sandstone

TAKE TIME OUT Consider relaxing stand-off

Make bold move in preferred direction

Yes Make bold move in reverse direction to Target sand Go back to Start of Horizontal section Decision Tree

Yes

Continue drilling ahead continuously assessing Sw & faulting/structure

Continue drilling ahead continuously assessing Sw & zonation

Find Target sandstone?

TAKE TIME OUT Look at alternative higher targets

TAKE TIME OUT Target sand not developed Run out of section

No

Yes

No At TD decision point?

Go to TD Decision Tree

Yes

9


Geosteering Strategies Decision Tree: Calling TD Vertical Section (ft) Plus x ft 0

50

100

150

200

250

300

0

Depth (ft) Plus y ft

20 40 60 80

TD?

TD?

TD?

100 120 140

Assess well performance using preferred measures E.g. mD.ft.& fractional flow

No At planned TD?

Yes

Performance Measures Met ?

Yes

Yes Added value by more PI?

Drill ahead Return to Start of TD Decision Tree

No

No Drill ahead Return to Start of TD Decision Tree

Performance Measures Met ? Yes Confirm TD Performance criteria


No

Yes Can TD Be extended ?

Drill ahead Return to Start of TD Decision Tree

No TAKE TIME OUT OH Sidetrack?

TD

10

5

05/10/2005

Geosteering Strategies Geosteering - Roles & Responsibilities Real clarity of Roles & Responsibilities is required to ensure that people know what is expected of them, that team members are not by-passed, & that the Well Objectives are met.

Strategic Decisions •Operations Geologist •Business Unit Geologist / Reservoir Engineer / Geophysicist •Wellsite Geologist

Tactical Decisions – need to be defined •Wellsite Geologist •Operations Geologist

11


Geosteering Strategies Geosteering Communications Wellsite Geologists & Directional Drillers MUST be talking frequently Wellsite Geologist to Directional Driller: •How the correlations are looking •What the bed dip is •Likely upcoming trajectory changes •How do FE parameters look; their impact on the rest of the well Directional Driller to Wellsite Geologist: •Upcoming nudges to maintain current target TVD •Directional trends •Torque, drag, hole cleaning, ledges


12

6

05/10/2005

Geosteering Strategies Geosteering – Communications contd. Wellsite Geologists & Operations Geologists MUST be talking frequently Wellsite geologist to Operations Geologist •How the correlations are looking •What the bed dip is •Likely upcoming trajectory changes •How do FE parameters look; their impact on the rest of the well •Directional trends •Torque, drag, hole cleaning, ledges Operations Geologist to Wellsite geologist •Thoughts about correlation & well position •Feedback from BU any thoughts on structure / faults in the rest of the well


13

7

Case Study Objectives 1. To construct a lithology log from offset wireline, MWD and cuttings information; this to be used by the drilling department to assist in writing the Detailed Drilling Plan. 2. To construct a Pressure Profile log to include Pore Pressure, Fracture Pressure and Overburden Pressure Gradient curves from offset wireline, MWD and drilling data. 3. To provide information about potential geological hazards and drilling problems to the drilling department.

Operations & Wellsite Geologist Well Planning & Geosteering Case Study

4. To perform real-time geosteering co-ordination and practice decision making techniques to land the well and drill the horizontal reservoir section. Well Data North Sea, HPHT horizontal oil producer. •

Target is dome structure, trending NW-SE. Well to enter target from south-east at 315º azimuth, into Calleva Sandstone reservoir dipping at 2.5º SE. Objective is to drill as much of the reservoir as possible, following the gentle dome structure and staying within the oil bearing window.

•

Oil water contact is prognosed at 4780m TVD

•

Target Information: (from one 1980s drilled exploration well) Upper Jurassic fluvial sandstone reservoir

Target MD: 5880m TVD: 4770m Inclination: 90º (well to have reached 90º inclination on entering the target sandstone)


Azimuth: 315º Well Profile: KOP: 3030m BUR: 1º/30m (to 90º)

Data Provided 1. Offset log comprising Drilling & Wireline Log Information. 2. Offset log comprising Drilling & Wireline Log Information. 3. Drill Cuttings Tasks 1. 2. 3. 4. 5.

Interpret expected lithologies using log information Use cuttings to confirm lithology profile Suggest mud systems and identify geological hazards Estimate expected pore pressure and fracture pressure from logs and offset data Participate in drilling the well on paper exercise: Choose appropriate geosteering drilling tools Choose appropriate LWD tools Land the well Drill reservoir


Formation Rodby (Marl) Kimmeridge Calleva (Sst)

Prognosed MD 4962 5418 5850

Oil/water contact

TVD 4580 4720 4770 4780

Survey Data MD 5220 5250 5280 5285

TVD 4673.77 4682.29 4690.3 4691.59

VS 1216.32 1245.09 1274.00 1278.5

Incl 73º 74º 75º 75º

VS 977.42 1408.00 1845.49

Incl 65º 80º 90º

Actual MD

TVD

Incl

PROPOSAL LISTING WELL: Location Comments

Tie-In

Minimum Curvature method

RKB-MSL

Calleva

25.00

UNITS:

m

DLS per

30.00

epoc98

m

Proj Azim

315.00

North

0.00

East

0.00

MD m

INCL Deg

AZI Deg

TVDBRKB m

TVDSS m

LAT N/S

DEP E/W

VS m

DLS deg/30m

0.0

0.00

0.0

0.00

-25.00

0.00

0.00

0.00

0.00

150.0

0.00

0.00

150.00

125.00

0.00

0.00

0.00

0.00

180.0

0.00

0.00

180.00

155.00

0.00

0.00

0.00

0.00

210.0

0.00

0.00

210.00

185.00

0.00

0.00

0.00

0.00

240.0

0.00

0.00

240.00

215.00

0.00

0.00

0.00

0.00

270.0

0.00

0.00

270.00

245.00

0.00

0.00

0.00

0.00

300.0

0.00

0.00

300.00

275.00

0.00

0.00

0.00

0.00

330.0

0.00

0.00

330.00

305.00

0.00

0.00

0.00

0.00

360.0

0.00

0.00

360.00

335.00

0.00

0.00

0.00

0.00

390.0

0.00

0.00

390.00

365.00

0.00

0.00

0.00

0.00

420.0

0.00

0.00

420.00

395.00

0.00

0.00

0.00

0.00

450.0

0.00

0.00

450.00

425.00

0.00

0.00

0.00

0.00

480.0

0.00

0.00

480.00

455.00

0.00

0.00

0.00

0.00

510.0

0.00

0.00

510.00

485.00

0.00

0.00

0.00

0.00

540.0

0.00

0.00

540.00

515.00

0.00

0.00

0.00

0.00

570.0

0.00

0.00

570.00

545.00

0.00

0.00

0.00

0.00

600.0

0.00

0.00

600.00

575.00

0.00

0.00

0.00

0.00

630.0

0.00

0.00

630.00

605.00

0.00

0.00

0.00

0.00

660.0

0.00

0.00

660.00

635.00

0.00

0.00

0.00

0.00

690.0

0.00

0.00

690.00

665.00

0.00

0.00

0.00

0.00

720.0

0.00

0.00

720.00

695.00

0.00

0.00

0.00

0.00

750.0

0.00

0.00

750.00

725.00

0.00

0.00

0.00

0.00

780.0

0.00

0.00

780.00

755.00

0.00

0.00

0.00

0.00

810.0

0.00

0.00

810.00

785.00

0.00

0.00

0.00

0.00

840.0

0.00

0.00

840.00

815.00

0.00

0.00

0.00

0.00

870.0

0.00

0.00

870.00

845.00

0.00

0.00

0.00

0.00

900.0

0.00

0.00

900.00

875.00

0.00

0.00

0.00

0.00

930.0

0.00

0.00

930.00

905.00

0.00

0.00

0.00

0.00

960.0

0.00

0.00

960.00

935.00

0.00

0.00

0.00

0.00

990.0

0.00

0.00

990.00

965.00

0.00

0.00

0.00

0.00

1020.0

0.00

0.00

1020.00

995.00

0.00

0.00

0.00

0.00

1050.0

0.00

0.00

1050.00

1025.00

0.00

0.00

0.00

0.00

1080.0

0.00

0.00

1080.00

1055.00

0.00

0.00

0.00

0.00

1110.0

0.00

0.00

1110.00

1085.00

0.00

0.00

0.00

0.00

1140.0

0.00

0.00

1140.00

1115.00

0.00

0.00

0.00

0.00

1170.0

0.00

0.00

1170.00

1145.00

0.00

0.00

0.00

0.00

1200.0

0.00

0.00

1200.00

1175.00

0.00

0.00

0.00

0.00

1230.0

0.00

0.00

1230.00

1205.00

0.00

0.00

0.00

0.00

1260.0

0.00

0.00

1260.00

1235.00

0.00

0.00

0.00

0.00

1290.0

0.00

0.00

1290.00

1265.00

0.00

0.00

0.00

0.00

1320.0

0.00

0.00

1320.00

1295.00

0.00

0.00

0.00

0.00

1350.0

0.00

0.00

1350.00

1325.00

0.00

0.00

0.00

0.00

1380.0

0.00

0.00

1380.00

1355.00

0.00

0.00

0.00

0.00

1410.0

0.00

0.00

1410.00

1385.00

0.00

0.00

0.00

0.00

1440.0

0.00

0.00

1440.00

1415.00

0.00

0.00

0.00

0.00

1470.0

0.00

0.00

1470.00

1445.00

0.00

0.00

0.00

0.00

1500.0

0.00

0.00

1500.00

1475.00

0.00

0.00

0.00

0.00

1530.0

0.00

0.00

1530.00

1505.00

0.00

0.00

0.00

0.00

1560.0

0.00

0.00

1560.00

1535.00

0.00

0.00

0.00

0.00

1590.0

0.00

0.00

1590.00

1565.00

0.00

0.00

0.00

0.00

1620.0

0.00

0.00

1620.00

1595.00

0.00

0.00

0.00

0.00

1650.0

0.00

0.00

1650.00

1625.00

0.00

0.00

0.00

0.00

1680.0

0.00

0.00

1680.00

1655.00

0.00

0.00

0.00

0.00

1710.0

0.00

0.00

1710.00

1685.00

0.00

0.00

0.00

0.00

1740.0

0.00

0.00

1740.00

1715.00

0.00

0.00

0.00

0.00

1770.0

0.00

0.00

1770.00

1745.00

0.00

0.00

0.00

0.00

1800.0

0.00

0.00

1800.00

1775.00

0.00

0.00

0.00

0.00

1830.0

0.00

0.00

1830.00

1805.00

0.00

0.00

0.00

0.00

1860.0

0.00

0.00

1860.00

1835.00

0.00

0.00

0.00

0.00

1890.0

0.00

0.00

1890.00

1865.00

0.00

0.00

0.00

0.00

1920.0

0.00

0.00

1920.00

1895.00

0.00

0.00

0.00

0.00

1950.0

0.00

0.00

1950.00

1925.00

0.00

0.00

0.00

0.00

1980.0

0.00

0.00

1980.00

1955.00

0.00

0.00

0.00

0.00

Page 1

2010.0

0.00

0.00

2010.00

1985.00

0.00

0.00

0.00

0.00

2040.0

0.00

0.00

2040.00

2015.00

0.00

0.00

0.00

0.00

2070.0

0.00

0.00

2070.00

2045.00

0.00

0.00

0.00

0.00

2100.0

0.00

0.00

2100.00

2075.00

0.00

0.00

0.00

0.00

2130.0

0.00

0.00

2130.00

2105.00

0.00

0.00

0.00

0.00

2160.0

0.00

0.00

2160.00

2135.00

0.00

0.00

0.00

0.00

2190.0

0.00

0.00

2190.00

2165.00

0.00

0.00

0.00

0.00

2220.0

0.00

0.00

2220.00

2195.00

0.00

0.00

0.00

0.00

2250.0

0.00

0.00

2250.00

2225.00

0.00

0.00

0.00

0.00

2280.0

0.00

0.00

2280.00

2255.00

0.00

0.00

0.00

0.00

2310.0

0.00

0.00

2310.00

2285.00

0.00

0.00

0.00

0.00

2340.0

0.00

0.00

2340.00

2315.00

0.00

0.00

0.00

0.00

2370.0

0.00

0.00

2370.00

2345.00

0.00

0.00

0.00

0.00

2400.0

0.00

0.00

2400.00

2375.00

0.00

0.00

0.00

0.00

2430.0

0.00

0.00

2430.00

2405.00

0.00

0.00

0.00

0.00

2460.0

0.00

0.00

2460.00

2435.00

0.00

0.00

0.00

0.00

2490.0

0.00

0.00

2490.00

2465.00

0.00

0.00

0.00

0.00

2520.0

0.00

315.0

2520.00

2495.00

0.00

0.00

0.00

0.00

315.00

2550.0

0.00

315.0

2550.00

2525.00

0.00

0.00

0.00

0.00

0.00

2580.0

0.00

315.0

2580.00

2555.00

0.00

0.00

0.00

0.00

0.00

2610.0

0.00

315.0

2610.00

2585.00

0.00

0.00

0.00

0.00

0.00

2640.0

0.00

315.0

2640.00

2615.00

0.00

0.00

0.00

0.00

0.00

2670.0

0.00

315.0

2670.00

2645.00

0.00

0.00

0.00

0.00

0.00

2700.0

0.00

315.0

2700.00

2675.00

0.00

0.00

0.00

0.00

0.00

2730.0

0.00

315.0

2730.00

2705.00

0.00

0.00

0.00

0.00

0.00

2760.0

0.00

315.0

2760.00

2735.00

0.00

0.00

0.00

0.00

0.00

2790.0

0.00

315.0

2790.00

2765.00

0.00

0.00

0.00

0.00

0.00

2820.0

0.00

315.0

2820.00

2795.00

0.00

0.00

0.00

0.00

0.00

2850.0

0.00

315.0

2850.00

2825.00

0.00

0.00

0.00

0.00

0.00

2880.0

0.00

315.0

2880.00

2855.00

0.00

0.00

0.00

0.00

0.00

2910.0

0.00

315.0

2910.00

2885.00

0.00

0.00

0.00

0.00

0.00

2940.0

0.00

315.0

2940.00

2915.00

0.00

0.00

0.00

0.00

0.00

2970.0

0.00

315.0

2970.00

2945.00

0.00

0.00

0.00

0.00

0.00

3000.0

0.00

315.0

3000.00

2975.00

0.00

0.00

0.00

0.00

0.00

3030.0

0.00

315.0

3030.00

3005.00

0.00

0.00

0.00

0.00

3060.0

1.00

315.0

3060.00

3035.00

0.19

-0.19

0.26

1.00

1.00

0.00

3090.0

2.00

315.0

3089.99

3064.99

0.74

-0.74

1.05

1.00

1.00

0.00

3120.0

3.00

315.0

3119.96

3094.96

1.67

-1.67

2.36

1.00

1.00

0.00

3150.0

4.00

315.0

3149.90

3124.90

2.96

-2.96

4.19

1.00

1.00

0.00

3180.0

5.00

315.0

3179.81

3154.81

4.63

-4.63

6.54

1.00

1.00

0.00

3210.0

6.00

315.0

3209.67

3184.67

6.66

-6.66

9.42

1.00

1.00

0.00

3240.0

7.00

315.0

3239.48

3214.48

9.06

-9.06

12.81

1.00

1.00

0.00

3270.0

8.00

315.0

3269.22

3244.22

11.83

-11.83

16.73

1.00

1.00

0.00

3300.0

9.00

315.0

3298.89

3273.89

14.96

-14.96

21.16

1.00

1.00

0.00

3330.0

10.00

315.0

3328.48

3303.48

18.47

-18.47

26.11

1.00

1.00

0.00

3360.0

11.00

315.0

3357.98

3332.98

22.33

-22.33

31.58

1.00

1.00

0.00

3390.0

12.00

315.0

3387.37

3362.37

26.56

-26.56

37.56

1.00

1.00

0.00

3420.0

13.00

315.0

3416.66

3391.66

31.15

-31.15

44.05

1.00

1.00

0.00

3450.0

14.00

315.0

3445.83

3420.83

36.10

-36.10

51.06

1.00

1.00

0.00

3480.0

15.00

315.0

3474.88

3449.88

41.41

-41.41

58.57

1.00

1.00

0.00

3510.0

16.00

315.0

3503.79

3478.79

47.08

-47.08

66.59

1.00

1.00

0.00

3540.0

17.00

315.0

3532.55

3507.55

53.11

-53.11

75.11

1.00

1.00

0.00

3570.0

18.00

315.0

3561.16

3536.16

59.49

-59.49

84.13

1.00

1.00

0.00

3600.0

19.00

315.0

3589.61

3564.61

66.22

-66.22

93.65

1.00

1.00

0.00

3630.0

20.00

315.0

3617.89

3592.89

73.30

-73.30

103.66

1.00

1.00

0.00

3660.0

21.00

315.0

3645.99

3620.99

80.73

-80.73

114.17

1.00

1.00

0.00

3690.0

22.00

315.0

3673.90

3648.90

88.50

-88.50

125.16

1.00

1.00

0.00

3720.0

23.00

315.0

3701.62

3676.62

96.62

-96.62

136.64

1.00

1.00

0.00

3750.0

24.00

315.0

3729.13

3704.13

105.08

-105.08

148.60

1.00

1.00

0.00

3780.0

25.00

315.0

3756.43

3731.43

113.88

-113.88

161.05

1.00

1.00

0.00

3810.0

26.00

315.0

3783.50

3758.50

123.01

-123.01

173.96

1.00

1.00

0.00

3840.0

27.00

315.0

3810.35

3785.35

132.47

-132.47

187.35

1.00

1.00

0.00

3870.0

28.00

315.0

3836.96

3811.96

142.27

-142.27

201.20

1.00

1.00

0.00

3900.0

29.00

315.0

3863.33

3838.33

152.39

-152.39

215.51

1.00

1.00

0.00

3930.0

30.00

315.0

3889.44

3864.44

162.84

-162.84

230.29

1.00

1.00

0.00

3960.0

31.00

315.0

3915.29

3890.29

173.60

-173.60

245.51

1.00

1.00

0.00

3990.0

32.00

315.0

3940.86

3915.86

184.69

-184.69

261.19

1.00

1.00

0.00

4020.0

33.00

315.0

3966.17

3941.17

196.08

-196.08

277.30

1.00

1.00

0.00

4050.0

34.00

315.0

3991.18

3966.18

207.79

-207.79

293.86

1.00

1.00

0.00

Page 2

0.00

4080.0

35.00

315.0

4015.91

3990.91

219.81

-219.81

310.85

1.00

1.00

0.00

4110.0

36.00

315.0

4040.33

4015.33

232.13

-232.13

328.28

1.00

1.00

0.00

4140.0

37.00

315.0

4064.44

4039.44

244.74

-244.74

346.12

1.00

1.00

0.00

4170.0

38.00

315.0

4088.24

4063.24

257.66

-257.66

364.38

1.00

1.00

0.00

4200.0

39.00

315.0

4111.72

4086.72

270.86

-270.86

383.06

1.00

1.00

0.00

4230.0

40.00

315.0

4134.87

4109.87

284.36

-284.36

402.14

1.00

1.00

0.00

4260.0

41.00

315.0

4157.68

4132.68

298.13

-298.13

421.62

1.00

1.00

0.00

4290.0

42.00

315.0

4180.15

4155.15

312.19

-312.19

441.50

1.00

1.00

0.00

4320.0

43.00

315.0

4202.27

4177.27

326.52

-326.52

461.77

1.00

1.00

0.00

4350.0

44.00

315.0

4224.03

4199.03

341.12

-341.12

482.42

1.00

1.00

0.00

4380.0

45.00

315.0

4245.43

4220.43

355.99

-355.99

503.45

1.00

1.00

0.00

4410.0

46.00

315.0

4266.45

4241.45

371.12

-371.12

524.84

1.00

1.00

0.00

4440.0

47.00

315.0

4287.10

4262.10

386.51

-386.51

546.60

1.00

1.00

0.00

4470.0

48.00

315.0

4307.37

4282.37

402.15

-402.15

568.72

1.00

1.00

0.00

4500.0

49.00

315.0

4327.25

4302.25

418.04

-418.04

591.19

1.00

1.00

0.00

4530.0

50.00

315.0

4346.73

4321.73

434.17

-434.17

614.00

1.00

1.00

0.00

4560.0

51.00

315.0

4365.82

4340.82

450.53

-450.53

637.15

1.00

1.00

0.00

4590.0

52.00

315.0

4384.49

4359.49

467.14

-467.14

660.63

1.00

1.00

0.00

4620.0

53.00

315.0

4402.75

4377.75

483.96

-483.96

684.43

1.00

1.00

0.00

4650.0

54.00

315.0

4420.60

4395.60

501.02

-501.02

708.54

1.00

1.00

0.00

4680.0

55.00

315.0

4438.02

4413.02

518.29

-518.29

732.97

1.00

1.00

0.00

4710.0

56.00

315.0

4455.01

4430.01

535.77

-535.77

757.69

1.00

1.00

0.00

4740.0

57.00

315.0

4471.57

4446.57

553.46

-553.46

782.71

1.00

1.00

0.00

4770.0

58.00

315.0

4487.69

4462.69

571.35

-571.35

808.01

1.00

1.00

0.00

4800.0

59.00

315.0

4503.36

4478.36

589.44

-589.44

833.59

1.00

1.00

0.00

4830.0

60.00

315.0

4518.59

4493.59

607.71

-607.71

859.44

1.00

1.00

0.00

4860.0

61.00

315.0

4533.36

4508.36

626.18

-626.18

885.55

1.00

1.00

0.00

4890.0

62.00

315.0

4547.68

4522.68

644.82

-644.82

911.91

1.00

1.00

0.00

4920.0

63.00

315.0

4561.53

4536.53

663.63

-663.63

938.52

1.00

1.00

0.00

4950.0

64.00

315.0

4574.91

4549.91

682.62

-682.62

965.37

1.00

1.00

0.00

4980.0

65.00

315.0

4587.83

4562.83

701.77

-701.77

992.45

1.00

1.00

0.00

5010.0

66.00

315.0

4600.27

4575.27

721.07

-721.07 1019.74

1.00

1.00

0.00

5040.0

67.00

315.0

4612.23

4587.23

740.52

-740.52 1047.26

1.00

1.00

0.00

5070.0

68.00

315.0

4623.71

4598.71

760.12

-760.12 1074.97

1.00

1.00

0.00

5100.0

69.00

315.0

4634.71

4609.71

779.86

-779.86 1102.88

1.00

1.00

0.00

5130.0

70.00

315.0

4645.21

4620.21

799.73

-799.73 1130.98

1.00

1.00

0.00

5160.0

71.00

315.0

4655.23

4630.23

819.72

-819.72 1159.26

1.00

1.00

0.00

5190.0

72.00

315.0

4664.75

4639.75

839.84

-839.84 1187.71

1.00

1.00

0.00

5220.0

73.00

315.0

4673.77

4648.77

860.07

-860.07 1216.32

1.00

1.00

0.00

5250.0

74.00

315.0

4682.29

4657.29

880.41

-880.41 1245.09

1.00

1.00

0.00

5280.0

75.00

315.0

4690.30

4665.30

900.85

-900.85 1274.00

1.00

1.00

0.00

5310.0

76.00

315.0

4697.82

4672.82

921.39

-921.39 1303.04

1.00

1.00

0.00

5340.0

77.00

315.0

4704.82

4679.82

942.02

-942.02 1332.21

1.00

1.00

0.00

5370.0

78.00

315.0

4711.31

4686.31

962.73

-962.73 1361.50

1.00

1.00

0.00

5400.0

79.00

315.0

4717.29

4692.29

983.51

-983.51 1390.90

0.00

1.00

0.00

5430.0

80.00

315.0

4722.76

4697.76 1004.37 -1004.37 1420.39

0.00

1.00

0.00

5460.0

80.00

315.0

4727.97

4702.97 1025.26 -1025.26 1449.94

0.00

0.00

0.00

5490.0

80.00

315.0

4733.18

4708.18 1046.15 -1046.15 1479.48

0.00

0.00

0.00

5520.0

80.00

315.0

4738.39

4713.39 1067.04 -1067.04 1509.03

1.00

0.00

0.00

5550.0

80.00

315.0

4743.60

4718.60 1087.93 -1087.93 1538.57

1.00

0.00

0.00

5580.0

81.00

315.0

4748.55

4723.55 1108.86 -1108.86 1568.16

1.00

1.00

0.00

5610.0

82.00

315.0

4752.98

4727.98 1129.84 -1129.84 1597.83

1.00

1.00

0.00

5640.0

83.00

315.0

4756.90

4731.90 1150.87 -1150.87 1627.57

1.00

1.00

0.00

5670.0

84.00

315.0

4760.29

4735.29 1171.94 -1171.94 1657.38

1.00

1.00

0.00

5700.0

85.00

315.0

4763.17

4738.17 1193.06 -1193.06 1687.24

1.00

1.00

0.00

5730.0

86.00

315.0

4765.52

4740.52 1214.21 -1214.21 1717.15

1.00

1.00

0.00

5760.0

87.00

315.0

4767.36

4742.36 1235.38 -1235.38 1747.09

1.00

1.00

0.00

5790.0

88.00

315.0

4768.66

4743.66 1256.57 -1256.57 1777.06

1.00

1.00

0.00

5820.0

89.00

315.0

4769.66

4744.66 1283.57 -1283.57 1815.25

1.00

1.00

0.00

5850.0

90.00

315.0

4769.93

4744.93 1304.78 -1304.78 1845.24

1.00

1.00

0.00

Page 3

General

Symbols Used in Log Interpretation

Gen-1 (former Gen-3)

Gen Resistivity of the zone Resistivity of the water in the zone Water saturation in the zone Mud Rm Adjacent bed Rs

hmc Rmc

Uninvaded zone Flushed zone

dh

(Bed thickness)

Mudcake

Rx o

h

Rt

Zone of transition or annulus

Rw

Ri

Sw

Rmf Sx o Rs

di dj Adjacent bed (Invasion diameters) ∆rj dh Hole diameter

© Schlumberger

Purpose This diagram presents the symbols and their descriptions and relations as used in the charts. See Appendixes D and E for identification of the symbols.

Description The wellbore is shown traversing adjacent beds above and below the zone of interest. The symbols and descriptions provide a graphical representation of the location of the various symbols within the wellbore and formations.

1

General

Estimation of Formation Temperature with Depth


Gen Temperature gradient conversions: 1°F/100 ft = 1.823°C/100 m 1°C/100 m = 0.5486°F/100 ft Annual mean surface temperature 27 16

Temperature (°C)

50

75

25

50

100 75

125 100

150

175

125

150

175 1

5 2 B 0.6

10

0.8

1.0

1.2

1.4 1.6°F/100 ft

Geothermal gradient

3

A

Depth (thousands of feet)

1.09

1.46

1.82

2.19

4

2.55 2.92°C/100 m

15 5

Depth (thousands of meters)

6

20

7 25 8

80 60

100

150 100

Annual mean surface temperature

200 150

250 200

300 250

350 300

350

Temperature (°F)

© Schlumberger

3

General

Equivalent NaCl Salinity of Salts


Gen

2.0

Li (2.5)†

OH (5.5)†

2.0

NH4 (1.9)†

Mg

1.5

K Ca

1.0

CO3 Na and CI (1.0)

1.0 K

Multiplier SO4 0.5

NO3 (0.55)† Br (0.44)†

Ca

CO3

HCO3

SO4

I (0.28)

†

HCO3

0

0

Mg –0.5 10

20

50

100

200

500

1,000 2,000

5,000 10,000 20,000

50,000 100,000

300,000

Total solids concentration (ppm or mg/kg)

† Multipliers that do not vary appreciably for low concentrations

(less than about 10,000 ppm) are shown at the left margin of the chart © Schlumberger

Purpose This chart is used to approximate the parts-per-million (ppm) concentration of a sodium chloride (NaCl) solution for which the total solids concentration of the solution is known. Once the equivalent concentration of the solution is known, the resistivity of the solution for a given temperature can be estimated with Chart Gen-6. Description The x-axis of the semilog chart is scaled in total solids concentration and the y-axis is the weighting multiplier. The curve set represents the various multipliers for the solids typically in formation water.

Example Given:

Find: Answer:

Formation water sample with solids concentrations of calcium (Ca) = 460 ppm, sulfate (SO4) = 1,400 ppm, and Na plus Cl = 19,000 ppm. Total solids concentration = 460 + 1,400 + 19,000 = 20,860 ppm. Equivalent NaCl solution in ppm. Enter the x-axis at 20,860 ppm and read the multiplier value for each of the solids curves from the y-axis: Ca = 0.81, SO4 = 0.45, and NaCl = 1.0. Multiply each concentration by its multiplier: (460 × 0.81) + (1,400 × 0.45) + (19,000 × 1.0) = 20,000 ppm.

5

General

Resistivity of NaCl Water Solutions


Gen Conversion approximated by R2 = R1 [(T1 + 6.77)/(T2 + 6.77)]°F or R2 = R1 [(T1 + 21.5)/(T2 + 21.5)]°C 10 8 6 5

ppm

grains/gal at 75°F

4

200

10

300

15

2

400

20 25 30

1

500 600 700 800 1,0 00 1,2 00 1,4 00 1,7 00 2,0 00

50

3,0 00 4,0 00 5,0 00 6,0 00 7,0 00 8,0 00 10, 00 12, 0 000 14, 000 17, 0 20, 00 000

150

3

0.8 0.6 0.5 0.4 Resistivity of solution (ohm-m)

0.3 0.2

0.1 0.08 0.06 0.05 0.04 0.03 0.02 300 ,000

0.01 °F 50 °C 10

75 20

30

100 40

125 150 200 50 60 70 80 90 100 Temperature

© Schlumberger

8

250 300 350 400 120 140 160 180 200

30, 000 40, 000 50, 000 60, 000 70, 0 80, 00 000 100 , 120 000 140,000 ,0 170 00 , 200 000 250,000 , 280 000 ,00 0

40

100

200 250 300 400 500

1,000 1,500 2,000 2,500 3,000 4,000 5,000

10,000 15,000 20,000

NaCl concentration (ppm or grains/gal)

Gamma Ray and Spontaneous Potential

Schlumberger

Rweq Determination from ESSP

SP-1

Clean formations

This chart and nomograph calculate the equivalent formation water resistivity, R weq, from the static spontaneous potential, E SSP, measurement in clean formations. Enter the nomograph with ESSP in mV, turning through the reservoir temperature in °F or °C to define the R mfeq /R weq ratio. From this value, pass through the R mfeq value to define R weq. For predominantly NaCl muds, determine R mfeq as follows: a. If R mf at 75°F (24°C) is greater than 0.1 ohm-m, correct R mf to formation temperature using Chart Gen-9, and use R mfeq = 0.85 R mf.

Example: SSP = 100 mV at 250°F R mf = 0.70 ohm-m at 100°F or 0.33 ohm-m at 250°F Therefore, R mfeq = 0.85 × 0.33 = 0.28 ohm-m at 250°F R weq = 0.025 ohm-m at 250°F E SSP = –K c log(R mfeq /R weq ) K C = 61 + 0.133 T°F K C = 65 + 0.24 T°C

Rweq (ohm-m) 0.001

SP

b. If R mf at 75°F (24°C) is less than 0.1 ohm-m, use Chart SP-2 to derive a value of R mfeq at formation temperature. 0.005

Rmfeq /Rweq 0.3

0.3

0.4

0.4

0.5 0.6

0.6

0.8

0.8

1

1

Rmfeq (ohm-m) 0.01

0.01

0.02

0.02

0.04 0.06 aw /amf or Rmfe /Rwe

2

2

3

0.1

0.05

0.2

4

4

5 6

6

8

8

10

10

0.4 0.6

0.1

1

30

Formation temperature

40 50 +50

0

–50

F 0° F 50 0° 40 0°F C C 0° 30 25 00° C °F 2 00 0° 2 15 0°C °F 10 100 C 50° 0°C

20

–100

–150

ESSP, static spontaneous potential (mV)

–200

2

0.2

4 6 20

10

0.5

20 40

40 60

1.0

100 2.0

© Schlumberger

2-5

Spontaneous Potential—Wireline

Rweq versus Rw and Formation Temperature

SP-2 (customary, former SP-2)

0.001 500°F 400°F 300°F

0.002

200°F

SP

150°F 0.005 100°F 75°F 0.01 Saturation 0.02

Rweq or Rmfeq (ohm-m)

0.05

0.1

0.2

500°F 400° F 0.5

°F 75 at Cl Na

1.0

2.0 0.005

300° F 200° F 150 °F 100 ° 75° F F

0.01

0.02 0.03

0.05

0.1

0.2

0.3

0.5

1.0

2

3

4 5

Rw or Rmf (ohm-m) © Schlumberger

Purpose This chart is used to convert equivalent water resistivity (Rweq ) from Chart SP-1 to actual water resistivity (Rw). It can also be used to convert the mud filtrate resistivity (Rmf) to the equivalent mud filtrate resistivity (Rmfeq ) in saline mud. The metric version of this chart is Chart SP-3 on page 49. Description The solid lines are used for predominantly NaCl waters. The dashed lines are approximations for “average” fresh formation waters (for which the effects of salts other than NaCl become significant). 48

The dashed lines can also be used for gypsum-base mud filtrates. Example Given: Find: Answer:

From Chart SP-1, Rweq = 0.025 ohm-m at 250°F in predominantly NaCl water. Rw at 250°F. Enter the chart at the Rweq value on the y-axis and move horizontally right to intersect the solid 250°F line. From the intersection point, move down to find the Rw value on the x-axis. Rw = 0.03 ohm-m at 250°F.

Porosity—Wireline, LWD General

Sonic Tool Porosity Evaluation—Open Hole

Purpose This chart is used to convert sonic log slowness time (∆t) values into those for porosity (φ). Description There are two sets of curves on the chart. The blue set for matrix velocity (vma) employs a weighted-average transform. The red set is based on the empirical observation of lithology (see Reference 20). For both, the saturating fluid is assumed to be water with a velocity (vf) of 5,300 ft/s (1,615 m/s). Enter the chart with the slowness time from the sonic log on the x-axis. Move vertically to intersect the appropriate matrix velocity or lithology curve and read the porosity value on the y-axis. For rock mixtures such as limy sandstones or cherty dolomites, intermediate matrix lines may be interpolated. To use the weighted-average transform for an unconsolidated sand, a lack-of-compaction correction (Bcp) must be made. Enter the chart with the slowness time and intersect the appropriate compaction correction line to read the porosity on the y-axis. If the compaction correction is not known, it can be determined by working backward from a nearby clean water sand for which the porosity is known.

Example: Consolidated Formation Given: ∆t = 76 µs/ft in a consolidated formation with vma = 18,000 ft/s. Find: Porosity and the formation lithology (sandstone, dolomite, or limestone). Answer: 15% porosity and consolidated sandstone. Example: Unconsolidated Formation Given: Unconsolidated formation with ∆t = 100 µs/ft in a nearby water sand with a porosity of 28%. Find: Porosity of the formation for ∆t = 110 µs/ft. Answer: Enter the chart with 100 µs/ft on the x-axis and move vertically upward to intersect 28-p.u. porosity. This intersection point indicates the correction factor curve of 1.2. Use the 1.2 correction value to find the porosity for the other slowness time. The porosity of an unconsolidated formation with ∆t = 110 µs/ft is 34 p.u.

Lithology

vma (ft/s)

∆tma (µs/ft)

vma (m/s)

∆tma (µs/m)

Sandstone Limestone Dolomite

18,000–19,500 21,000–23,000 23,000–26,000

55.5–51.3 47.6–43.5 43.5–38.5

5,486–5,944 6,400–7,010 7,010–7,925

182–168 156–143 143–126

Por

continued on next page 201

Porosity—Wireline, LWD

Sonic Tool

Por-1

Porosity Evaluation—Open Hole

(customary, former Por-3)

vf = 5,300 ft/s 50

50 Time average Field observation

1.1

40

40

1.2 1.3

e

Q

Ca lci t

Do lom i

te

30

1.4

) ne to s e (lim

ne sto d n sa tz r ua

30

1.5 1.6 Bcp

Porosity, φ (p.u.)

Porosity, φ (p.u.) 20

20

26 , 23 000 21 ,000 19 ,000 18 ,500 ,00 0

vma (ft/s)

10

Por

10

0 30

40

50

60

70

80

90

Interval transit time, ∆t (µs/ft)

© Schlumberger

202

100

110

120

0 130


Sonic Tool

Por-2

Porosity Evaluation—Open Hole

(metric, former Por-3m)

vf = 1,615 m/s 50

50 Time average Field observation

1.1

40

40

1.2 1.3 Do l

ite om

30

te lci a C

1.4

e ton ds n sa rtz a Qu

1.6 Bcp

vma (m/s)

10

0 100

8 7,0 ,000 6 0 5, ,40 0 5,5 950 0 D 00 Ce C ol Qu men alci omit te e a rt t z s ed q an u ds artz ton e sand sto ne

Porosity, φ (p.u.)

20

30

1.5

Porosity, φ (p.u.)

20

10

Por

0 150

200

250

300

350

400

Interval transit time, ∆t (µs/m)

© Schlumberger

Purpose This chart is used similarly to Chart Por-1 with metric units.

203


Density Tool

Por-3

Porosity Determination—Open Hole

ρf (g/cm3)

(former Por-5)

1.0 0.9 0.8

ma

ρ

ma

ρ

ma

=2 = 2 .87 (d .83 olo

1.2 40

=2 mi te = 2 . 71 ) ( ca .68 lci =2 te .6 5 ) (q ua rtz sa nd sto ne )

1.1

ρ

ma

ρ

ma

ρ

30

Porosity, φ (p.u.)

φ=

20

ρma – ρb ρma – ρf

10

0 2.8

2.6

2.4 Bulk density, ρb (g/cm ) 3

2.31

2.2

2.0

*Mark of Schlumberger © Schlumberger

Por

Purpose This chart is used to convert grain density (g/cm3) to density porosity. Description Values of log-derived bulk density (ρb) corrected for borehole size, matrix density of the formation (ρma), and fluid density (ρf) are used to determine the density porosity (φD) of the logged formation. The ρf is the density of the fluid saturating the rock immediately surrounding the borehole—usually mud filtrate. Enter the borehole-corrected value of ρb on the x-axis and move vertically to intersect the appropriate matrix density curve. From the intersection point move horizontally to the fluid density line. Follow the porosity trend line to the porosity scale to read the formation

204

porosity as determined by the density tool. This porosity in combination with CNL* Compensated Neutron Log, sonic, or both values of porosity can help determine the rock type of the formation. Example Given:

Find: Answer:

ρb = 2.31 g/cm3 (log reading corrected for borehole effect), ρma = 2.71 g/cm3 (calcite mineral), and ρf = 1.1 g/cm3 (salt mud). Density porosity. φD = 25 p.u.

Porosity—Wireline

APS* Near-to-Array (APLC) and Near-to-Far (FPLC) Logs Epithermal Neutron Porosity Equivalence—Open Hole

Purpose This chart is used for the apparent limestone porosity recorded by the APS Accelerator Porosity Sonde or sidewall neutron porosity (SNP) tool to provide the equivalent porosity in sandstone or dolomite formations. It can also be used to obtain the apparent limestone porosity (used for the various crossplot porosity charts) for a log recorded in sandstone or dolomite porosity units. Description Enter the x-axis with the corrected near-to-array apparent limestone porosity (APLC) or near-to-far apparent limestone porosity (FPLC) and move vertically to the appropriate lithology curve. Then read the equivalent porosity on the y-axis. For APS porosity recorded in sandstone or dolomite porosity units enter that value on the y-axis and move horizontally to the recorded lithology curve. Then read the apparent limestone neutron porosity for that point on the x-axis. The APLC is the epithermal short-spacing apparent limestone neutron porosity from the near-to-array detectors. The log is automatically corrected for standoff during acquisition. Because it is epithermal this measurement does not need environmental corrections for temperature or chlorine effect. However, corrections for mud weight and actual borehole size should be applied (see Chart Neu-10). The short spacing means that the effect of density and therefore the lithology on this curve is minimal. The FPLC is the epithermal long-spacing apparent limestone neutron porosity acquired from the near-to-far detectors. Because it is epithermal this measurement does not need environmental corrections for temperature or chlorine effect. However, corrections for mud weight and actual borehole size should be applied (see Chart Neu-10). The long spacing means that the density and therefore lithology effect on this curve is pronounced, as seen on Charts Por-13 and Por-14.

The HPLC curve is the high-resolution version of the APLC curve. The same corrections apply. Resolution

Short Spacing

Normal

APLC Epithermal neutron porosity (ENPI)† HPLC HNPI†

Enhanced † Not

Long Spacing FPLC HFLC

formation-salinity corrected.

Example: Equivalent Porosity Given: APLC = 25 p.u. and FPLC = 25 p.u. Find: Porosity for sandstone and for dolomite. Answer:

Sandstone porosity from APLC = 28.5 p.u. and sandstone porosity from FPLC = 30 p.u. Dolomite porosity = 24 and 20 p.u., respectively.

Example: Apparent Porosity Given: Clean sandstone porosity = 20 p.u. Find: Apparent limestone neutron porosity. Answer: Enter the y-axis at 20 p.u. and move horizontally to the quartz sandstone matrix curves. Move vertically from the points of intersection to the x-axis and read the apparent limestone neutron porosity values. APLC = 16.8 p.u. and FPLC = 14.5 p.u.

Por


Porosity—Wireline

APS* Near-to-Array (APLC) and Near-to-Far (FPLC) Logs

Por-4

Epithermal Neutron Porosity Equivalence—Open Hole

(former Por-13a)

40 APLC FPLC SNP

20

Qu ar tz

True porosity for indicated matrix material, φ (p.u.)

sa nd sto ne

30

ite lc Ca

) ne o t es (lim ite lom o D

10

0 0

10

20

Apparent limestone neutron porosity, φSNPcor (p.u.) Apparent limestone neutron porosity, φAPScor (p.u.) *Mark of Schlumberger © Schlumberger

Por

206

30

40

Porosity—Wireline General

Thermal Neutron Tool

Por-5

Porosity Equivalence—Open Hole

(former Por-13b)

40 Formation salinity 0 ppm 250,000 ppm

TNPH NPHI

True porosity for indicated matrix material, φ (p.u.)

Qu ar tz sa nd C sto ne

30

20

c al

ite

n to es m (li

e) ite lom o D

10

0 0

10

20

30

40

Apparent limestone neutron porosity, φCNLcor (p.u.)


Purpose This chart is used to convert CNL* Compensated Neutron Log porosity curves (TNPH or NPHI) from one lithology to another. It can also be used to obtain the apparent limestone porosity (used for the various crossplot porosity charts) from a log recorded in sandstone or dolomite porosity units. Description To determine the porosity of either quartz sandstone or dolomite enter the chart with the either the TNPH or NPHI corrected apparent limestone neutron porosity (φCNLcor) on the x-axis. Move vertically to intersect the appropriate curve and read the porosity for quartz sandstone or dolomite on the y-axis. The chart has a built-in salinity correction for TNPH values.

NPHI NPOR TNPH

Example Given:

Find: Answer:

Thermal neutron porosity (ratio method) Neutron porosity (environmentally corrected and enhanced vertical resolution processed) Thermal neutron porosity (environmentally corrected)

Por

Quartz sandstone formation, TNPH = 18 p.u. (apparent limestone neutron porosity), and formation salinity = 250,000 ppm. Porosity in sandstone. From the TNPH porosity reading of 18 p.u. on the x-axis, project a vertical line to intersect the quartz sandstone dashed red curve. From the y-axis, the porosity of the sandstone is 24 p.u.

207


CNL* Compensated Neutron Log and Litho-Density* Tool (fresh water in invaded zone)

Por-11 (former CP-1e)

Porosity and Lithology—Open Hole

Liquid-Filled Borehole (ρf = 1.000 g/cm3 and Cf = 0 ppm) 1.9 45

2.0

40

Sulfur Salt Ap pro xim cor gas ate rec tion

2.2

35

15

2.4

30

e 25 ton s nd 25 sa tz r e) a Qu ton s e (lim 20 e t 25 lci Ca

20

15

10 10

2.6

35

30

30

25

20

15

te 20 mi o l Do

2.5 5

35

30

y sit ro o P

2.3

10

15 5

Density porosity, φD (p.u.) (ρma = 2.71 g/cm3, ρf = 1.0 g/cm3)

5

0

2.7

40

35

2.1

Bulk density, ρb (g/cm3)

45

40

10

0

0 5

–5

2.8 0

–10

2.9

3.0

–15

Anhydrite 0

10

20

30

Por

40

Corrected apparent limestone neutron porosity, φCNLcor (p.u.)


213


CNL* Compensated Neutron Log and Litho-Density* Tool (salt water in invaded zone)

Por-12 (former CP-11)


Liquid-filled borehole (ρf = 1.190 g/cm3 and Cf = 250,000 ppm) 1.9 45

2.0

45 45

Sulfur Salt

40 Ap pro xim cor gas ate rec tion

2.1

2.2

40


10 10

5 2.6

30

35

30 25

30

20

25

15

Density porosity, φD (p.u.) (ρma = 2.71 g/cm3, ρf = 1.19 g/cm3)

10

5

0

2.7

35

30

ne sto d n 25 sa rtz 20 e) a Qu ton s 0 e 2 (lim te i c l Ca 15 20 ite lom o D 15

15

2.5

35

y sit ro o P 25

2.3

2.4

40

35

5 10

0

0

5 –5

2.8

0

–10

2.9 –15 3.0

Anhydrite 0

10

20

30

40

Corrected apparent limestone neutron porosity, φCNLcor (p.u.) *Mark of Schlumberger © Schlumberger

Por Purpose This chart is used similarly to Chart Por-11 with CNL Compensated Neutron Log and Litho-Density values to approximate the lithology and determine the crossplot porosity in the saltwater-invaded zone.

214

Example Given: Find: Answer:

Corrected apparent neutron limestone porosity = 16.5 p.u. and bulk density = 2.38 g/cm3. Crossplot porosity and lithology. Crossplot porosity = 20 p.u. The lithology is approximately 55% quartz and 45% limestone.


APS* and Litho-Density* Tools

Por-13


(former CP-1g)

Liquid-Filled Borehole (ρf = 1.000 g/cm3 and Cf = 0 ppm) 1.9 45

APLC FPLC

40

2.0

40 35 35

Ap pro xim cor gas ate rec tion

2.1

2.2


ity os r Po 20 20

15 15

2.6

30 e n o t ds an 5 e) s 2 ton 30 rtz s a e Qu (lim e t i 20 lc Ca 25 25 ite m lo Do 0 0 2 2

25

35

35

25

30

10

55

15

15

5

00

2.7

15

10 10

2.5

40

30 30

2.3

2.4

40

35

10

10

0 5

5

2.8 00

2.9

e rit yd h An

3.0 0

10

20

30

40

Corrected APS apparent limestone neutron porosity, φAPScor (p.u.) *Mark of Schlumberger © Schlumberger

Por Purpose This chart is used to determine the lithology and porosity from the Litho-Density bulk density and APS Accelerator Porosity Sonde porosity log curves (APLC or FPLC). This chart applies to boreholes filled with freshwater drilling fluid; Chart Por-14 is used for saltwater fluids. Description Enter either the APLC or FPLC porosity on the x-axis and the bulk density on the y-axis. Use the blue matrix curves for APLC porosity values and the red curves for FPLC porosity values. Anhydrite plots on separate curves. The gas correction direction is indicated for formations containing gas. Move parallel to the blue correction line if the APLC porosity is used or to the red correction line if the FPLC porosity is used.


APLC porosity = 8 p.u. and bulk density = 2.2 g/cm3. Approximate quartz sandstone porosity. Enter at 8 p.u. on the x-axis and 2.2 g/cm3 on the y-axis to find the intersection point is in the gas-in-formation correction region. Because the APLC porosity value was used, move parallel to the blue gas correction line until the blue quartz sandstone curve is intersected at approximately 19 p.u.

215


APS* and Litho-Density* Tools (saltwater formation)

Por-14


(former CP-1h)

Liquid-Filled Borehole (ρf = 1.190 g/cm3 and Cf = 250,000 ppm) 1.9 APLC FPLC

45 45

2.0 40 40

Ap pro xim cor gas ate rec tion

2.1


15 15

10 10

2.5

15 5

00

2.7

30 e n sto nd 25 a ) zs 30 20 20 ne art sto Qu 0 e 2 (lim 5 ite 2 25 c l a te i C 15 lom Do 0 20 2

35

25

40

40

35

30

10

55

2.6

35

30 30

ity ros o P 25

2.4

40

35 35

2.2

2.3

45

10

0

5

15

10

5

2.8 00

2.9

e rit yd h An

3.0 0

10

20

30

40

Corrected APS apparent limestone neutron porosity, φAPScor (p.u.) *Mark of Schlumberger © Schlumberger

Por Purpose This chart is used similarly to Chart Por-13 to determine the lithology and porosity from Litho-Density* bulk density and APS* porosity log curves (APLC or FPLC) in saltwater boreholes.

216

Example Given: APLC porosity = 8 p.u. and bulk density = 2.2 g/cm3. Find: Approximate quartz sandstone porosity. Answer: Enter 8 p.u. on the x-axis and 2.2 g/cm3 on the y-axis to find the intersection point is in the gas-in-formation correction region. Because the APLC porosity value was used, move parallel to the blue gas correction line until the blue quartz sandstone curve is intersected at approximately 20 p.u.

Porosity—LWD General

adnVISION475* 4.75-in. Azimuthal Density Neutron Tool

Por-15


Fresh Water, Liquid-Filled Borehole (ρf = 1.0 g/cm3) 1.9

Salt

40

2.0

40

35

ity os r Po

2.1

40

35

30 30 e ton s nd sa 25 tr z ) a ne Qu sto e lim 20 e( t i 25 lc Ca ite om l o 20 D

2.2

2.3 Bulk density, ρb (g/cm3)

20

15

2.4

15

10

2.5

30

10 5

2.6

15

5 0

2.7

35

25

10 0 5

2.8 0

2.9

Anhydrite 3.0 –5

0

5

10

15

20

25

30

35

40

45

Corrected apparent limestone neutron porosity, φADNcor (p.u.) *Mark of Schlumberger © Schlumberger

Por Purpose This chart is used to determine the crossplot porosity and lithology from the adnVISION475 4.75-in. density and neutron porosity. Description Enter the chart with the adnVISION475 corrected apparent limestone neutron porosity (from Chart Neu-31) and bulk density. The intersection of the two values is the crossplot porosity. The position of the point of intersection between the matrix curves represents the relative percentage of each matrix material.

Example Given:

φADNcor = 20 p.u. and ρb = 2.24 g/cm3.

Find: Answer:

Crossplot porosity and matrix material. 25 p.u. in sandstone.

217



Por-16



40 2.0

40

35 2.1

y 30 sit ro o P 30 25 e n sto nd 25 a s e) tz 20 ton ar s u e Q lim 20 e( t 25 i lc Ca

2.2


15

2.4

15

10 2.5

10

5

35 30

te mi o l Do

15

5

2.6

0 2.7

20

35

10 0 5

2.8 0

2.9

3.0 –5

0

5

10

15

20

25

30

35

40

45

Corrected apparent limestone neutron porosity, φADNcor (p.u.)

Por


Purpose This chart uses the bulk density and apparent limestone porosity from the adnVISION 6.75-in. Azimuthal Density Neutron tool to determine the lithology of the logged formation and the crossplot porosity. Description This chart is applicable for logs obtained in freshwater drilling fluid. Enter the corrected apparent limestone porosity and the bulk density on the x- and y-axis, respectively. Their intersection point determines the lithology and crossplot porosity.

218


Corrected adnVISION675 apparent limestone porosity = 20 p.u. and bulk density = 2.3 g /cm3. Porosity and lithology type. Entering the chart at 20 p.u. on the x-axis and 2.3 g /cm3 on the y-axis corresponds to a crossplot porosity of 21.5 p.u. and formation comprising approximately 60% quartz sandstone and 40% limestone.



Por-17



40 2.0

40

35

2.2

30

30 e n sto nd 25 a s e) tz ton ar s u e Q lim 20 e( t i lc ite Ca lom o D

20

15

20

10 2.5

25

15

2.4

30

25


35

40

ity ros o P

35

2.1

10

5

15 5

2.6

10

0 2.7

0 5

0

2.8

2.9

3.0 –5

0

5

10

15

20

25

30

35

40

45

Corrected apparent limestone neutron porosity, φADNcor (p.u.)

Por


Purpose This chart is used similarly to Chart Por-15 to determine the lithology and crossplot porosity from adnVISION825 8.25-in. Azimuthal Density Neutron values.

219


Sonic and Thermal Neutron Crossplot Porosity and Lithology—Open Hole, Freshwater Invaded

Purpose This chart is used to determine crossplot porosity and an approximation of lithology for sonic and thermal neutron logs in freshwater drilling fluid.

Example Given:

Description Enter the corrected neutron porosity (apparent limestone porosity) on the x-axis and the sonic slowness time (∆t) on the y-axis to find their intersection point, which describes the crossplot porosity and lithology composition of the formation. Two sets of curves are drawn on the chart. The blue set of curves represents the crossplot porosity values using the sonic time-average algorithm. The red set of curves represents the field observation algorithm.

Find: Answer:

Por

220

Thermal neutron apparent limestone porosity = 20 p.u. and sonic slowness time = 89 µs/ft in freshwater drilling fluid. Crossplot porosity and lithology. Enter the neutron porosity on the x-axis and the sonic slowness time on the y-axis. The intersection point is at about 25 p.u. on the field observation line and 24.5 p.u. on the time-average line. The matrix is quartz sandstone.


Sonic and Thermal Neutron Crossplot

Por-20

Porosity and Lithology—Open Hole, Freshwater Invaded

(customary, former CP-2c)

tf = 190 µs/ft and Cf = 0 ppm 110

35

40

40

Time average Field observation

35 35 30

35

30

35

Qu 30 30 ar tz sa nd sto ne 25

20

25

30

90

25 25

Po ros ity

100

15

Sonic transit time, ∆t (µs/ft)

20

5

30

15 15

10

5

10

Sa lt

20

15

10

70

25

15

20

20 Ca lci t 20 e (lim es t 25 one Do ) lom ite

80

60 10

10

15

Por

5

0

0

50

An hy dr ite 0

5 5

10

0

5

0

0

40 0

10

20

30

40

Corrected CNL* apparent limestone neutron porosity, φCNLcor (p.u.) *Mark of Schlumberger © Schlumberger

221


Sonic and Thermal Neutron Crossplot

Por-21


(metric, former CP-2cm)

t f = 620 µs/m and Cf = 0 ppm 360

40

40

Time average Field observation

15

25

10

20

5

200

15

10

5

10

15

Sa lt

20

15

10

15

20

240

30

20

20

260 Sonic transit time, ∆t (µs/m)

Ca lci te ( Do 25 25 lime lom sto ne ite ) 25

20

280

220

35

30

30

25 25

Po ros ity

35

Qu 30 30 ar tz sa nd sto ne 30

320

300

35 35

35

340

10

15

0

0 5

180

5

5

An hy dri te

Por

10

0 5

0

160

0

0

140

0 *Mark of Schlumberger © Schlumberger

10

Purpose This chart is used similarly to Chart Por-20 for metric units. 222

20

30

Corrected CNL* apparent limestone neutron porosity, φCNLcor (p.u.)

40


Density and Sonic Crossplot Porosity and Lithology—Open Hole, Freshwater Invaded

Purpose This chart is used to determine porosity and lithology for sonic and density logs in freshwater-invaded zones.

Example Given:

Description Enter the chart with the bulk density on the y-axis and sonic slowness time on the x-axis. The point of intersection indicates the type of formation and its porosity.

Find: Answer:

Bulk density = 2.3 g /cm3 and sonic slowness time = 82 µs/ft. Crossplot porosity and lithology. Limestone with a crossplot porosity = 24 p.u.

Por



Density and Sonic Crossplot

Por-22


(customary, former CP-7)

t f = 189 µs/ft and ρf = 1.0 g/cm3 1.8 Time average Field observation Sylvite 1.9

40

40

2.0 Salt

40 Sulfur

Trona

30

40

2.1

30

30

2.2

40

30

ity os r Po 2.3

20

Gypsum

30

2.4

2.6

2.7

Por

20 10 10 Polyhalite

00 Do lom ite

2.8

2.9

10

0 Ca Qu ar 0 lcit tz e( sa lim nd es sto ton ne e) 10 0 0 10

10

2.5

20


20

20 20

30

Anhydrite 3.0 40

50

60

70

80

90

Sonic transit time, ∆t (µs/ft) © Schlumberger

224

100

110

120


Density and Sonic Crossplot

Por-23


(metric, former CP-7m)

t f = 620 µs/m and ρf = 1.0 g/cm3 1.8 Time average Field observation Sylvite 1.9

40

40

2.0

40

Salt Sulfur 2.1

30

40

Trona

30

30

30

2.2

40

y sit ro o P

2.3 20

Gypsum

30

2.4

2.7

2.8

2.9

Por

10

Polyhalite

0 0 Do lom ite

2.6

Qu 0 Ca ar 0 lc tz ite sa (lim nd sto es ton ne e) 10 0 0 10

10

20 10 10

2.5

20


20

20 20

30

Anhydrite 3.0 150

200

© Schlumberger

250

300

350

400

Sonic transit time, ∆t (µs/m)

Purpose This chart is used similarly to Chart Por-22 for metric units. 225


Density, Neutron, and Rxo Logs Porosity Identification in Hydrocarbon-Bearing Formation—Open Hole

Purpose This nomograph is used to estimate porosity in hydrocarbon-bearing formations by using density, neutron, and resistivity in the flushed zone (Rxo) logs. The density and neutron logs must be corrected for environmental effects and lithology before entry to the nomograph. The chart includes an approximate correction for excavation effect, but if hydrocarbon density (ρh) is <0.25 g /cm3 (gas), the chart may not be accurate in some extreme cases: ■ ■

very high values of porosity (>35 p.u.) coupled with medium to high values of hydrocarbon saturation (Shr) Shr = 100% for medium to high values of porosity.

Description Connect the apparent neutron porosity value on the appropriate neutron porosity scale (CNL* Compensated Neutron Log or sidewall neutron porosity [SNP] log) with the corrected apparent density porosity on the density scale with a straight line. The intersection point on the φ1 scale indicates the value of φ1. Draw a line from the φ1 value to the origin (lower right corner) of the chart for ∆φ versus Shr. Enter the chart with Shr from (Shr = 1 – Sxo) and move vertically upward to determine the porosity correction factor (∆φ) at the intersection with the line from the φ1 scale. This correction factor algebraically added to the porosity φ1 gives the corrected porosity.

Por

230

Example Given:

Find: Answer:

Corrected CNL apparent neutron porosity = 12 p.u., corrected apparent density porosity = 38 p.u., and Shr = 50%. Hydrocarbon-corrected porosity. Enter the 12-p.u. φcor value on the CNL scale. A line from this value to 38 p.u. on the φDcor scale intersects the φ1 scale at 32.2 p.u. The intersection of a line from this value to the graph origin and Shr = 50% is ∆φ = –1.6 p.u. Hydrocarbon-corrected porosity: 32.2 – 1.6 = 30.6 p.u.


Density, Neutron, and Rxo Logs

Por-26

Porosity Identification in Hydrocarbon-Bearing Formation—Open Hole

φcor (CNL*) 50

φcor (SNP)

φ1

50

(former CP-9)

φDcor 50

50

(p.u.)

40

40

40

40

30

30

30

30

–5

20

20

20

20

–4

–3 ∆φ (p.u.) 10

10

10

10

–2

Por

–1

0

0

0

0

0 100

80

60

40

20

0

Shr (%) *Mark of Schlumberger © Schlumberger

231

Lithology—Wireline General

Density and NGS* Natural Gamma Ray Spectrometry Tool Mineral Identification—Open Hole

Purpose This chart is a method for identifying the type of clay in the wellbore. The values of the photoelectric factor (Pe) from the Litho-Density* log and the concentration of potassium (K) from the NGS Natural Gamma Ray Spectrometry tool are entered on the chart. Description Enter the upper chart with the values of Pe and K to determine the point of intersection. On the lower chart, plotting Pe and the ratio of thorium and potassium (Th/K) provides a similar mineral evaluation. The intersection points are not unique but are in general areas defined by a range of values.

Lith

182

Example Given:

Find: Answer:

Environmentally corrected thorium concentration (ThNGScorr) = 10.6 ppm, environmentally corrected potassium concentration (KNGScorr) = 3.9%, and Pe = 3.2. Mineral concentration of the logged clay. The intersection points from plotting values of Pe and K on the upper chart and Pe and Th/K ratio = 10.6/3.9 = 2.7 on the lower chart suggest that the clay mineral is illite.

Lithology—Wireline

Density and NGS* Natural Gamma Ray Spectrometry Tool

Lith-1

Mineral Identification—Open Hole

(former CP-18)

10

8 Glauconite Chlorite

Biotite

6 Photoelectric factor, Pe 4

Illite Muscovite

Montmorillonite 2 Kaolinite

0 0

2

4

6

8

10

Potassium concentration, K (%)

10

8 Glauconite Biotite

Lith

Chlorite

6 Photoelectric factor, Pe Mixed layer

4

Illite Muscovite

2 Montmorillonite

0 0.1

0.2

0.3

0.6

1

2

3

6

Kaolinite

10

20

30

60

100

Thorium/potassium ratio, Th/K *Mark of Schlumberger © Schlumberger

183


NGS* Natural Gamma Ray Spectrometry Tool

Lith-2

Mineral Identification—Open Hole

(former CP-19)

Heav y tho rium -bea ring mine rals

20

15 Thorium (ppm)

12

Th/K = 25

25 Th /K =

Possible 100% kaolinite, montmorillonite, illite “clay line”

100% illite point

Kaolinite K= Th/

~70% illite lay er c -lay d e Mix

M on tm or illo nit e

10

5

= 2.0 Th/K ~40% mica

Illite

Micas

Glauconite

e orit Chl 0 0

3.5

1

2

3

~30% glauconite

Th/K = 0.6

Feldspar

Th/K = 0.3

Potassium evaporites, ~30% feldspar 4

5

Potassium (%)


Lith

Purpose This chart is used to determine the type of minerals in a shale formation from concentrations measured by the NGS Natural Gamma Ray Spectrometry tool. Description Entering the chart with the values of thorium and potassium locates the intersection point used to determine the type of radioactive minerals that compose the majority of the clay in the formation.

184

A sandstone reservoir with varying amounts of shaliness and illite as the principal clay mineral usually plots in the illite segment of the chart with Th/K between 2.0 and 3.5. Less shaly parts of the reservoir plot closer to the origin, and shaly parts plot closer to the 70% illite area.


Platform Express* Three-Detector Lithology Density Tool Porosity and Lithology—Open Hole

Purpose This chart is used to determine the lithology and porosity of a formation. The porosity is used for the water saturation determination and the lithology helps to determine the makeup of the logged formation. Description Note that this chart is designed for fresh water (fluid density [ρf] = 1.0 g/cm3) in the borehole. Chart Lith-4 is used for saltwater (ρf = 1.1 g/cm3) formations. Values of photoelectric factor (Pe) and bulk density (ρb) from the Platform Express Three-Detector Lithology Density (TLD) tool are entered into the chart. At the point of intersection, porosity and lithology values can be determined.

Example Given:

Find: Answer:

Freshwater drilling mud, Pe = 3.0, and bulk density = 2.73 g/cm3. Freshwater drilling mud, Pe = 1.6, and bulk density = 2.24 g/cm3. Porosity and lithology. For the first set of conditions, the formation is a dolomite with 8% porosity. The second set is for a quartz sandstone formation with 30% porosity.

Lith



Platform Express* Three-Detector Lithology Density Tool

Lith-3


(former CP-16)

Fresh Water (ρf = 1.0 g/cm3), Liquid-Filled Borehole

0

40

2.0

Salt

40

1.9

30

40

2.1

10

2.5

20

10


Dolomite

2.4

20

ne) (limesto Calcite

30

2.3

20

Quartz sandstone

30

2.2

0

2.6

10

Lith

0

2.7

0

2.8

0

Anhydrite

2.9

3.0 0

1

2

3 Photoelectric factor, Pe


186

4

5

6


Platform Express* Three-Detector Lithology Density Tool

Lith-4


(former CP-17)

Salt Water (ρf = 1.1 g/cm3), Liquid-Filled Borehole 1.9

40

40

0

Salt

2.0

10


10

20

2.5

Dolomite

2.4

20

ne) (limesto Calcite

30

2.3

20

Quartz sandstone

2.2

30

30

40

2.1

10

0

2.6

Lith

0

2.7

0

2.8

0

Anhydrite

2.9

3.0 0

1

2


This chart is used similarly to Chart Lith-3 for lithology and porosity determination with values of photoelectric factor (Pe) and

3

4

5

6

Photoelectric factor, Pe

bulk density (ρb) from the Platform Express TLD tool in saltwater borehole fluid. 187

General Lithology—Wireline, Drillpipe LWD

Density Tool

Lith-5

Apparent Matrix Volumetric Photoelectric Factor—Open Hole

(former CP-20)

Fresh water (0 ppm), ρf = 1.0 g/cm3, U f = 0.398 Salt water (200,000 ppm), ρf = 1.11 g/cm3, U f = 1.36

3.0

0

2.5

10 20

2.0

30 Bulk density, ρb (g/cm3)

40

6

5

4

3

2

1

Photoelectric factor, Pe

4

6

8

10

12

Apparent total porosity, φta (%)

14

Apparent matrix volumetric photoelectric factor, Umaa

© Schlumberger

Lith

Purpose This chart is used to determine the apparent matrix volumetric photoelectric factor (Umaa) for the Chart Lith-6 percent lithology determination. Description This chart is entered with the values of bulk density (ρb) and Pe from a density log. The value of the apparent total porosity (φta) must also be known. The appropriate solid lines on the right-hand side of the chart that indicate a freshwater borehole fluid or dotted lines that represent saltwater borehole fluid are used depending on the salinity of the borehole fluid. Uf is the fluid photoelectric factor.

188


Pe = 4.0, ρb = 2.5 g/cm3, φta = 25%, and freshwater borehole fluid. Apparent matrix volumetric photoelectric factor (Umaa). Enter the chart with the Pe value (4.0) on the left-hand x-axis, and move upward to intersect the curve for ρb = 2.5 g/cm3. From that intersection point, move horizontally right to intersect the φta value of 25%, using the blue freshwater curve. Move vertically downward to determine the Umaa value on the right-hand x-axis scale: Umaa = 13.

Lithology—Wireline, LWD General

Density Tool Lithology Identification—Open Hole

Purpose This chart is used to identify the rock mineralogy through comparison of the apparent matrix grain density (ρmaa) and apparent matrix volumetric photoelectric factor (Umaa). Description The values of ρmaa and Umaa are entered on the y- and x-axis, respectively. The rock mineralogy is identified by the proximity of the point of intersection of the two values to the labeled points on the plot. The effect of gas, salt, etc., is to shift data points in the directions shown by the arrows.


ρmaa = 2.74 g/cm3 (from Chart Lith-9 or Lith-10) and Umaa = 13 (from Chart Lith-5). Matrix composition of the formation. Enter the chart with ρmaa = 2.74 g/cm3 on the y-axis and Umaa = 13 on the x-axis. The intersection point indicates a matrix mixture of 20% dolomite and 80% calcite.

Lith



Density Tool

Lith-6

Lithology Identification—Open Hole

(former CP-21)

2.2

2.3 Salt

on Gas directi

2.4

2.5

K-feldspar

2.6 Apparent matrix grain density, ρmaa (g/cm3) 2.7

% calcit e

20

Quartz

40

60

80

80

Calcite 60

% tz ar qu

2.8

20 40

40 60

20

Dolomite

2.9

Lith

%

80

Barite

ite lom o d

Heavy minerals

Anhydrite

3.0 Kaolinite Illite 3.1 2

4

6

8

10

12

Apparent matrix volumetric photoelectric factor, Umaa

© Schlumberger

190

14

16

Lithology—Wireline, LWD

Environmentally Corrected Neutron Curves M–N Plot for Mineral Identification—Open Hole

Purpose This chart is used to help identify mineral mixtures from sonic, density, and neutron logs. Description Because M and N slope values are practically independent of porosity except in gas zones, the porosity values they indicate can be correlated with the mineralogy. (See Appendix E for the formulas to calculate M and N from sonic, density, and neutron logs.) Enter the chart with M on the y-axis and N on the x-axis. The intersection point indicates the makeup of the formation. Points for binary mixtures plot along a line connecting the two mineral points. Ternary mixtures plot within the triangle defined by the three constituent minerals. The effect of gas, shaliness, secondary porosity, etc., is to shift data points in the directions shown by the arrows.

The lines on the chart are divided into numbered groups by porosity range as follows: 1. φ = 0 (tight formation) 2. φ = 0 to 12 p.u. 3. φ = 12 to 27 p.u. 4. φ = 27 to 40 p.u. Example Given: Find: Answer:

M = 0.79 and N = 0.51. Mineral composition of the formation. The intersection of the M and N values indicates dolomite in group 2, which has a porosity between 0 to 12 p.u.

Lith



Environmentally Corrected Neutron Curves

Lith-7

M–N Plot for Mineral Identification—Open Hole

(former CP-8)

1.1 Freshwater mud ρf = 1.0 Mg/m3, t f = 620 µs/m ρf = 1.0 g/cm3, t f = 189 µs/ft Gypsum

Saltwater mud ρf = 1.1 Mg/m3, t f = 607 µs/m ρf = 1.1 g/cm3, t f = 185 µs/ft

1.0

s Ga r o lt sa

Secondary porosity 0.9

vma = 5943 m/s = 19,500 ft/s

Quartz sandstone

Calcite (limestone) 0.8

1 2 34

vma = 5486 m/s = 18,000 ft/s

Dolomite M

324

1

Anhydrite

0.7

Sulfur Approximate shale region

0.6

Lith

0.5

0.3

0.4

0.5

0.6 N

© Schlumberger

192

0.7

0.8


Environmentally Corrected APS* Curves M–N Plot for Mineral Identification—Open Hole

Purpose This chart is used to help identify mineral mixtures from APS Accelerator Porosity Sonde neutron logs. Description Because M and N values are practically independent of porosity except in gas zones, the porosity values they indicate can be correlated with the mineralogy. (See Appendix E for the formulas to calculate M and N from sonic, density, and neutron logs.) Enter the chart with M on the y-axis and N on the x-axis. The intersection point indicates the makeup of the formation. Points for binary mixtures plot along a line connecting the two mineral points. Ternary mixtures plot within the triangle defined by the three constituent minerals. The effect of gas, shaliness, secondary porosity, etc., is to shift data points in the directions shown by the arrows.

The lines on the chart are divided into numbered groups by porosity range as follows: 1. φ = 0 (tight formation) 2. φ = 0 to 12 p.u. 3. φ = 12 to 27 p.u. 4. φ = 27 to 40 p.u. Because the dolomite spread is negligible, a single dolomite point is plotted for each mud. Example Given: Find: Answer:

M = 0.80 and N = 0.55. Mineral composition of the formation. Dolomite.

Lith



Environmentally Corrected APS* Curves

Lith-8

M–N Plot for Mineral Identification—Open Hole

(former CP-8a)

1.1 Freshwater mud ρf = 1.0 Mg/m3, t f = 620 µs/m ρf = 1.0 g/cm3, t f = 189 µs/ft Saltwater mud ρf = 1.1 Mg/m3, t f = 607 µs/m ρf = 1.1 g/cm3, t f = 185 µs/ft

Gypsum 1.0

s Ga r o lt sa

Secondary porosity 0.9

vma = 5943 m/s = 19,500 ft/s

Quartz sandstone

Calcite (limestone) 0.8

12 3,4

Dolomite

vma = 5486 m/s = 18,000 ft/s

M

Anhydrite

0.7

Sulfur Approximate shale region

0.6

Lith

0.5

0.3

0.4

0.5

0.6 N


194

0.7

0.8


Bulk Density or Interval Transit Time and Apparent Total Porosity Apparent Matrix Parameters—Open Hole

Purpose Charts Lith-9 (customary units) and Lith-10 (metric units) provide values of the apparent matrix internal transit time (t maa) and apparent matrix grain density (ρmaa) for the matrix identification (MID) Charts Lith-11 and Lith-12. With these parameters the identification of rock mineralogy or lithology through a comparison of neutron, density, and sonic measurements is possible.

Example Given:

Find: Answer:

Apparent crossplot porosity from density-neutron = 20%, ρb = 2.4 g/cm3, apparent crossplot porosity from neutron-sonic = 30%, and t = 82 µs/ft. ρmaa and t maa. ρmaa = 2.75 g/cm3 and t maa = 46 µs/ft.

Description Determining the values of t maa and ρmaa to use in the MID Charts Lith-11 and Lith-12 requires three steps. First, apparent crossplot porosity is determined using the appropriate neutron-density and neutron-sonic crossplot charts in the “Porosity” section of this book. For data that plot above the sandstone curve on the charts, the apparent crossplot porosity is defined by a vertical projection to the sandstone curve. Second, enter Chart Lith-9 or Lith-10 with the interval transit time (t) to intersect the previously determined apparent crossplot porosity. This point defines t maa. Third, enter Chart Lith-9 or Lith-10 with the bulk density (ρb) to again intersect the apparent crossplot porosity and define ρmaa. The values determined from Charts Lith-9 and Lith-10 for tmaa and ρmaa are cross plotted on the appropriate MID plot (Charts Lith-11 and Lith-12) to identify the rock mineralogy by its proximity to the labeled points on the plot.

Lith



Bulk Density or Interval Transit Time and Apparent Total Porosity

Lith-9

Apparent Matrix Parameters—Open Hole


Fluid Density = 1.0 g/cm3 Apparent matrix transit time, t maa (µs/ft) 130 3.0

120

110

100

90

80

70

60

50

40

30 130

2.9

120

2.8

110 40

2.7

100 Apparent crossplot porosity

30

90

20

10

2.5

80

De ns ity -n eu tro n


Ne ut ro nso ni c

2.6

2.4

70

10

2.3

60

20

2.2

50

30

2.1

40

40

2.0

Lith

30 3.0

2.9

2.8

2.7

2.6

2.5

2.4

Apparent matrix density, ρmaa (g/cm3) © Schlumberger

196

2.3

2.2

2.1

2.0

Interval transit time, t (µs/ft)

General Lithology—Wireline, LWD

Bulk Density or Interval Transit Time and Apparent Total Porosity

Lith-10

Apparent Matrix Parameters—Open Hole


Fluid Density = 1.0 g/cm3 Apparent matrix transit time, t maa (µs/m) 3.0

350

325

300

275

250

225

200

175

150

125

100

2.9

325 40

2.8

2.7

30

Ne ut ro nso ni c

2.6

300

Apparent crossplot porosity

275

250

20

10

2.5

225

De ns ity -n eu tro n


350

2.4

200

10

2.3

175

20

2.2

150

30

2.1

Interval transit time, t (µs/m)

125

40

2.0

Lith

100 3.0

2.9

2.8

2.7

2.6

2.5

2.4

2.3

2.2

2.1

2.0

Apparent matrix density, ρmaa (g/cm3) © Schlumberger

Purpose Charts Lith-9 (customary units) and Lith-10 (metric units) provide values of the apparent matrix internal transit time (t maa) and apparent matrix grain density (ρmaa) for the matrix identification (MID) Charts Lith-11 and Lith-12. With these parameters the identification of rock mineralogy or lithology through a comparison of neutron, density, and sonic measurements is possible.

197


Density Tool Matrix Identification (MID)—Open Hole

Purpose Charts Lith-11 and Lith-12 are used to establish the type of mineral predominant in the formation. Description Enter the appropriate (customary or metric units) chart with the values established from Charts Lith-9 or Lith-10 to identify the predominant mineral in the formation. Salt points are defined for two tools, the sidewall neutron porosity (SNP) and the CNL* Compensated Neutron Log. The presence of secondary porosity in the form of vugs or fractures displaces the data points parallel to the apparent matrix internal transit time (tmaa) axis. The presence of gas displaces points to the right on the chart. Plotting some shale points to establish the shale trend lines helps in the identification of shaliness. For fluid density (ρf) other than 1.0 g/cm3 use the table to determine the multiplier to correct the apparent total density porosity before entering Chart Lith-11 or Lith-12.

Lith

198


ρf

Multiplier

1.00 1.05 1.10 1.15

1.00 0.98 0.95 0.93

ρmaa = 2.75 g/cm3, t maa = 56 µs/ft (from Chart Lith-9), and ρf = 1.0 g/cm3. The predominant mineral. The formation consists of both dolomite and calcite, which indicates a dolomitized limestone. The formation used in this example is from northwest Florida in the Jay field. The vugs (secondary porosity) created by the dolomitization process displace the data point parallel to the dolomite and calcite points.

General Lithology—Wireline, LWD

Density Tool

Lith-11

Matrix Identification (MID)—Open Hole


2.0 Salt (CNL* log) Salt (SNP)

2.1

2.2

2.3

2.4

on cti ire d s Ga

2.5 ρmaa (g/cm3)

2.6 Quartz 2.7

Calcite

2.8 Dolomite 2.9 Anhydrite

3.0

Lith 3.1 30

40

50

60

70

tmaa (µs/ft)


199


Density Tool

Lith-12

Matrix Identification (MID)—Open Hole


2.0 Salt (CNL* log) Salt (SNP)

2.1

2.2

2.3

2.4

on cti ire d s Ga

2.5 ρmaa (g/cm3)

2.6 Quartz 2.7

Calcite

2.8 Dolomite 2.9

Anhydrite

3.0

Lith 3.1 100

120

140

160 t maa (µs/m)


Purpose Chart Lith-12 is used similarly to Chart Lith-11 to establish the mineral type of the formation.

200

180

200

220

240

Resistivity

Schlumberger

Dual Laterolog–Rxo Device

Rint-9b

DLT-D/E LLD–LLS–Rxo device

Thick beds, 8-in. [203-mm] hole, no annulus, no transition zone, Rxo /Rm = 50, use data corrected for borehole effect 100

20

80

30

40

50

100

0.50 0.75

80

1.01

60

1.27

70 40

60

1.52 2.03

120

50 3.04

Rt Rxo

30 1.1

di (in.)

30

1.2

20

di (m)

1.3

15

100

1.4 1.6

20

1.8 15

10 8

Rt RLLD

10

6 7 RLLD /Rxo

4

5

3 3 2 2 1.5

1.5

Rint

1 0.8

Rt Rxo

di (in.) di (m)

0.6 100 2.54 60 0.4 0.3

0.2 0.4

0.4

1.52 40 30 1.01 20 0.2 0.75 0.50 0.6

0.8 1.0

1.5

2

3

4

6

8

10

15

20

30

40

50

RLLD /RLLS © Schlumberger

6-7

Logging Tool Response in Sedimentary Minerals

Appendix B Name

Formula

ρLOG (g/cm3)

φSNP (p.u.)

φCNL (p.u.)

φAPS† (p.u.)

(µsec/ft)

(µsec/ft)

–1

56.0

88.0

t

c

t

s

ε (farad/m)

tp GR (nsec/m) (API units)

Σ (c.u.)

Pe

U

1.8

4.8

1.8

3.9

3.5

1.8

3.7

5.0

11

48

45

6.0

19

18

Silicates Quartz

SiO2

2.64

–1

–2

β-Cristobalite

SiO2

2.15

–2

–3

Opal (3.5% H2O)

SiO2 (H2O).1209

2.13

4

2

Garnet ‡

Fe3Al2(SiO4)3

4.31

3

7

Hornblende ‡

Ca2NaMg2Fe2 AlSi8O22(O,OH)2

3.20

4

8

Tourmaline

NaMg3Al6B3Si6O2(OH)4

3.02

16

22

2.1

6.5

7450

Zircon

ZrSiO4

4.50

–1

–3

69

311

6.9

Calcite

CaCO3

2.71

0

0

0

49.0

88.4

5.1

13.8

7.5

9.1

7.1

Dolomite

CaCO3MgCO3

2.85

2

1

1

44.0

72

3.1

9.0

6.8

8.7

4.7

Ankerite

Ca(Mg,Fe)(CO3)2

2.86

0

1

9.3

27

Siderite

FeCO3

3.89

5

12

15

57

Hematite

Fe2O3

5.18

4

11

42.9

21

111

101

Magnetite

Fe3O4

5.08

3

9

73

22

113

103

Geothite

FeO(OH)

4.34

50+

60+

19

83

85

Limonite ‡

FeO(OH)(H2O)2.05

3.59

50+

60+

13

47

Gibbsite

Al(OH)3

2.49

50+

60+

Hydroxyapatite

Ca5(PO4)3OH

3.17

5

8

42

5.8

18

9.6

Chlorapatite

Ca5(PO4)3CL

3.18

–1

–1

42

6.1

19

130

Fluorapatite

Ca5(PO4)3F

3.21

–1

–2

42

5.8

19

8.5

Carbonapatite

(Ca5(PO4)3)2CO3H2O

3.13

5

8

5.6

17

9.1

Orthoclase

KAISi3O8

2.52

–2

–3

2.9

7.2

4.4–6.0

7.0–8.2

~220

16

Anorthoclase

KAISi3O8

2.59

–2

–2

2.9

7.4

4.4–6.0

7.0–8.2

~220

16

Microcline

KAISi3O8

2.53

–2

–3

2.9

7.2

4.4–6.0

7.0–8.2

~220

16

1.7

4.4

4.4–6.0

7.0–8.2

7.5

3.1

8.6

4.4–6.0

7.0–8.2

7.2

2.4

6.7

6.2–7.9

8.3–9.4

4.8

14

6.3

19

58

43.8

81.5

4.65

7.2

4.3

Carbonates

3

47

22 6.8–7.5

8.8–9.1

52

Oxidates

56.9

79.3

102.6

9.9–10.9 10.5–11.0

71

1.1

23

Phosphates

Feldspars—Alkali ‡ 69

Feldspars—Plagioclase ‡ Albite

NaAlSi3O8

2.59

–1

–2

–2

Anorthite

CaAl2Si2O8

2.74

–1

–2

Muscovite

KAl2(Si3AlO10)(OH)2

2.82

12

~20

~13

Glauconite

K 0.7(Mg,Fe2,Al) (Si4,Al10)O2(OH)

2.86

~38

~15

Biotite

K(Mg,Fe)3(AlSi3O10)(OH)2

~2.99

~21

~11

Phlogopite

KMg3(AlSi3O10)(OH)2

49

85

45

Micas ‡

†APS

~11

49

149

50.8

224

50

207

~270

17 21

4.8–6.0

7.2–8.1

~275

30 33

porosity derived from near-to-array ratio (APLC) value, which may vary for individual samples

‡Mean

For more information see Reference 41.

B-5

Logging Tool Response in Sedimentary Minerals

Appendix B Name

Formula

ρLOG (g/cm3)

φSNP (p.u.)

φCNL (p.u.)

φAPS† (p.u.)

t

c

(µsec/ft)

t

s

(µsec/ft)

Pe

U

ε (farad/m)

tp GR (nsec/m) (API units)

Σ (c.u.)

Clays ‡ Kaolinite

Al4Si4O10(OH)8

2.41

34

~37

~34

1.8

4.4

~5.8

~8.0

80–130

14

Chlorite

(Mg,Fe,Al)6(Si,Al)4 O10(OH)8

2.76

37

~52

~35

6.3

17

~5.8

~8.0

180–250

25

Illite

K1–1.5Al4(Si7–6.5,Al1–1.5) O20(OH)4

2.52

20

~30

~17

3.5

8.7

~5.8

~8.0

250–300

18

Montmorillonite

(Ca,Na)7(Al,Mg,Fe)4 (Si,Al)8O20(OH)4(H2O)n

2.12

~60

~60

2.0

4.0

~5.8

~8.0

150–200

14

Halite

NaCl

2.04

–2

–3

21

67.0

4.7

9.5

5.6–6.3

7.9–8.4

754

Anhydrite

CaSO4

2.98

–1

–2

2

50

5.1

15

6.3

8.4

12

Gypsum

CaSO4(H2O)2

2.35

50+

60+

60

52

4.0

9.4

4.1

6.8

19

Trona

Na2CO3NaHCO3H2O

2.08

24

35

65

0.71

1.5

16

Tachhydrite

CaCl2(MgCl2)2(H2O)12

1.66

50+

60+

92

3.8

6.4

406

Sylvite

KCl

1.86

–2

–3

8.5

16

Carnalite

KClMgCl2(H2O)6

1.57

41

60+

4.1

Langbeinite

K2SO4(MgSO4)2

2.82

–1

–2

Polyhalite

K2SO4Mg SO4(CaSO4)2(H2O)2

2.79

14

Kainite

MgSO4KCl(H2O)3

2.12

Kieserite

MgSO4H2)

Epsomite

Evaporites 120

500+

565

6.4

~220

369

3.6

10

~290

24

25

4.3

12

~200

24

40

60+

3.5

7.4

~245

195

2.59

38

43

1.8

4.7

14

MgSO4(H2O)7

1.71

50+

60+

1.2

2.0

21

Bischofite

MgCl2(H2O)6

1.54

50+

60+

2.6

4.0

323

Barite

BaSO4

4.09

–1

–2

267

1090

6.8

Celestite

SrSO4

3.79

–1

–1

55

209

7.9

Pyrite

FeS2

4.99

–2

–3

17

85

90

Marcasite

FeS2

4.87

–2

–3

17

83

88

Pyrrhotite

Fe7S8

4.53

–2

–3

21

93

94

Sphalerite

ZnS

3.85

–3

–3

36

138

Chalopyrite

CuFeS2

4.07

–2

–3

27

109

102

Galena

PbS

6.39

–3

–3

1630

10,400

13

Sulfur

S

2.02

–2

–3

122

5.4

11

20

Anthracite

CH.358N.009O.022

1.47

37

38

105

0.16

0.23

8.7

Bituminous

CH.793N.015O.078

1.24

50+

60+

120

0.17

0.21

14

Lignite

CH.849N.015O.211

1.19

47

52

160

0.20

0.24

13

100

4.6–4.8

7.2–7.3

Sulfides 39.2

62.1

7.8–8.1

9.3–9.5

25

Coals

†APS

porosity derived from near-to-array ratio (APLC) value, which may vary for individual samples

‡Mean

For more information see Reference 41.

B-6

Water Saturation Grid for Porosity Versus Resistivity

Appendix A

For FR = 5000

0.62 φ2.15

0.20

Resistivity scale may be multiplied by 10 for use in a higher range 4000

0.25

0.30 3000 0.35 2500

0.40 0.45

2000

0.50

0.60 0.70 0.80 1000

0.90 1.0

Resistivity

Conductivity

1500

1.2

500

1.4 1.6 1.8 2.0

400

2.5 3.0

300 200 150 100 50 25 10 0

4.0 5.0 6.0 8.0 10 15 20 30 40 50 100 200

∞

t , ρb φ FR

A-3

FEL 4 Company : Well : Interval : 15800.00 - 16035.00 feet Created :

FORMATION EVALUATION LOG Cuttings

Rate of Penetration ft/hr

60

90

120

150

4

6

8

50

70

90

5

Ethane ppm

500000

Propane ppm

500000

5

iso-Butane ppm

500000

5

n-Butane ppm

500000

5

iso-Pentane ppm

500000

10

Ditch Gas % (Backup) 30

500000

110 5

RESISTIVITY Ohm.m 2

20

200

2000

Ohm.m

Lithology Description

INTERPRETED

30

2

Methane ppm

LITHOLOGY

100

5

FLUOR CUT

200

OIL

300

GAMMA API

CORE

400

MD feet 1:500

500

Ditch Gas %

n-Pentane ppm 50

500

5000

50000

500000

800

ISOTUBE TAKEN @ 15800'

MD: 15828', INC: 9.40 deg, AZM: 65.27 deg, TVD: 15053.71'

15850

DEPTH: 15800' WOB: 8-24 klbs PPRESS: 3817 psi SPM: 117 GPM: 585 TORQ: 40 kft.lbs RPM: 22

MDST: m gry-m dk gry-olv blk, occ brn blk, mod frm-frm, occ hd, sb blky-blky, pred sb blky, sli-occ slty, microcarb, n calc

CG: 0.3%

15900 MD: 15922', INC: 9.53 deg, AZM: 64.99 deg, TVD: 15146.42'

15950

FM: 8.9%

ISOTUBE TAKEN @ 15952' CIRCULATE GAS THROUGH CHOKE

C1, C2, C3, IC4, NC4, IC5, NC5

Sun 1st May 2005 Mon 2nd May 2005

INCREASE MUD WEIGHT FROM 14.0 ppg TO 14.5 ppg @ 15975' MD

16000

MW: 14.5 ppg, PV/YP: 39/23, Vis: 59sec, Gels: 20/27/28, E.S: 670 V DRILLER'S DEPTH @ 16034' MD (TVD 15256.28')

FORMATION EVALUATION LOG Cuttings

Rate of Penetration ft/hr

60

90

120

150

4

6

8

50

70

90

5

Ethane ppm

500000

Propane ppm

500000

5

iso-Butane ppm

500000

5

n-Butane ppm

500000

5

iso-Pentane ppm

500000

10

Ditch Gas % (Backup) 30

500000

110 5

RESISTIVITY Ohm.m 2

20

200

Ohm.m

2000

Lithology Description

INTERPRETED

30

2

Methane ppm

LITHOLOGY

100

5

FLUOR CUT

200

OIL

300

GAMMA API

CORE

400

MD feet 1:500

500

Ditch Gas %

Company Well Interval Created

:

HEL 4

: : 15800.00 - 16035.00 feet :

Gas Ratio Plot C1C2 1000

10

C2

10000

1

GWR

100

1

C1C3 1000

10

C3

10000

1

C1C4 1000

10

iC4

10000

1

C1C5 1000

10

nC4

10000

10

iC5

10000

%

ANALYSIS CDANAL OIL

1

RESIDUAL OIL

100

GAS/LIGHT OIL

LHR

GAS

1

INTERPRETED

10

10000

INTERPRETED

1

C1 RATIOS

C1 ppm

100 10

LITHOLOGY

1000

OIL CHARACTER OIL CHARACTER

CHROMATOGRAPH DATA

LITHOLOGY

100

GAS

UNPRODUCTIVE

10 ft/hr

CORE

1

MD feet 1:500

ROP

nC5

100

1000

10000

800 15850


15900

CG: 0.3%

15950

FM: 8.9%

16000

Gas Ratio Plot 100

1000

GAS 1

10

OIL CHARACTER OIL CHARACTER

CHROMATOGRAPH DATA

C1 RATIOS

100

1

C1C2 1000

10

C2

10000

1

GWR

100

1

C1C3 1000

10

C3

10000

1

C1C4 1000

10

iC4

10000

1

C1C5 1000

10

nC4

10000

10

iC5

10000

%

nC5

100

1000

10000

ANALYSIS CDANAL OIL

LHR

RESIDUAL OIL

1

GAS

10000

GAS/LIGHT OIL

C1 ppm

100 10

UNPRODUCTIVE

10 ft/hr

CORE

1

MD feet 1:500

ROP

DDL 4 Company : Well : Interval : 15800.00 - 16035.00 feet Created : ENGINEERING SUMMARY PLOT WEIGHT ON BIT

RATE OF PENETRATION 400

100

20

INTERPRETED

30 klbf

40

50

10

HOOKLOAD 80

160

240 klbf

20

30 kft.lb

50

75

MAX TORQUE 320

400

10

20

30 kft.lb

PUMP PRESS

RPM BIT 40

150 RPM

225

300

1000

50

75

150 RPM

225

3000 psi

4000

TOTAL GAS 5000

4

8

300

300

600

900 USgl/min

12

16

20

16

18

16

20

16

18

%

MUD FLOW IN

RPM TABLE 40

2000

1200

ECD TD 1500

10

12

14 ppg


15850


10

LITHOLOGY

300 200 ft/hr

MD feet 1:500

500

AVG TORQUE

CG: 0.3%


15950 16000

Sun 1st May 2005 Mon 2nd May 2005

FM: 8.9%

ENGINEERING SUMMARY PLOT WEIGHT ON BIT

RATE OF PENETRATION 400

100

10

INTERPRETED

LITHOLOGY

300 200 ft/hr

MD feet 1:500

500

20

30 klbf

AVG TORQUE 40

50

10

HOOKLOAD 80

160

240 klbf

20

30 kft.lb

40

50

75

MAX TORQUE 320

400

10

20

30 kft.lb

PUMP PRESS

RPM BIT 150 RPM

225

300

1000

50

75

150 RPM

225

3000 psi

4000

5000

4

8

300

300

600

900 USgl/min

12 %

MUD FLOW IN

RPM TABLE 40

2000

TOTAL GAS

1200

ECD TD 1500

10

12

14 ppg

PDL 4 Company : Well : Interval : 15800.00 - 16035.00 feet Created :

PRESSURE DATA PLOT

ft/hr

WEIGHT ON BIT

50

0

klbf

INTERPRETED

0

LITHOLOGY

ROP

MD feet 1:500

PENETRATION RATE 1000

100

ROTARY SPEED

TORQUE

SURFACE RPM

AVERAGE

200

300 RPM

400

500

10

200

300 RPM

30 kft.lb

40

DXC

GAS DATA TOTAL GAS

2

50

0.1

1

10

100

%

MAXIMUM

BIT RPM 100

20

DXC DATA 0.2

400

500

10

20

30 kft.lb

40

50

800

MD: 15828', INC: 9.40 deg, AZM: 65.27 deg, TVD: 15053.71'

15850


CG: 0.3% 15900

MD: 15922', INC: 9.53 deg, AZM: 64.99 deg, TVD: 15146.42' 15950

FM: 8.9%

CIRCULATE GAS THROUGH CHOKE

INCREASE MUD WEIGHT FROM 14.0 ppg TO 14.5 ppg @ 15975' MD MW: 14.5 ppg, PV/YP: 39/23, Vis: 59sec, Gels: 20/27/28, E.S: 670 V

Sun 1st May 2005 Mon 2nd May 2005 16000

PRESSURE DATA PLOT

ft/hr

50

WEIGHT ON BIT klbf

0

INTERPRETED

0

LITHOLOGY

ROP

MD feet 1:500

PENETRATION RATE 1000

100

ROTARY SPEED

TORQUE

SURFACE RPM

AVERAGE

200

300 RPM

400

500

10

200

300 RPM

30 kft.lb

40

50

400

500

10

20

30 kft.lb

DXC

GAS DATA TOTAL GAS

2

0.1

1

10

%

MAXIMUM

BIT RPM 100

20

DXC DATA 0.2

40

50

100

Company Well Interval Created Block Height

110

0

ft Surface Torque

15

0

kft.lb CDS Temperature [RWD]

250

TM hours 1:3600

0

: ECD TIME LOG : : 21/Apr/2005 20:00:00 to 24/Apr/2005 06:00:40 : 24/Apr/2005 13:00:52

degF

10

Mud Weight In

15 0

Mud Flow In

1500

10

ppg Actual ECD Flow Off [RWD]

15 0

USgl/min Standpipe Pressure

5000

10

ppg Actual ECD [RWD]

COMMENTS

psi 15

ppg

Start MWD Run 3 21:00:00

22:00:00

Drilling @ 12638 ft Downlink Slow Circ Rates 23:00:00 Repair hose leak Survey 00:00:00 22/Apr/2005 Downlink Downlink 01:00:00

02:00:00

Downlink

Downlink Downlink Downlink

03:00:00

04:00:00 Survey

Company Well Interval Created Caliper

22

in 100

CDS Temperature [RWD]

0

degF Gamma Ray App [RWD]

250

150

: : 10935.00 - 13247.19 feet : 9/2/2005 2:09:28 PM

TVD feet 1:500

12

:

0.2

Resistivity [AT] [LS] 2MHz [RWD]

20

0.2

Ohm.m Resistivity [AT] [LS] 400 kHz [RWD]

20

0.2

Ohm.m Resistivity [PD] [LS] 2MHz [RWD]

API

1000

Rate of Penetration

0.2

0

Ohm.m Resistivity [PD] [LS] 400kHz [RWD] Ohm.m

0

ft/hr Time Since Drilled

600

min

10950

11000

11050

11100

11150

11200

11250

1.65

Bulk Density Comp [RWD]

2.65

g/cc -0.25 DRHM [RWD]

g/cc

20

60 20

0.25

NPSM

pu

0

Company Well Field Rig County State Country

AZIMUTHAL GAMMA RAY RESISTIVITY Log as of:ABC1/2-3 Offshore North Sea United Kingdom

Company Well Interval Created CDS Temperature [MWD]

0

degF Gamma Ray UP [MWD]

0

API Gamma Ray DOWN [MWD]

150

0

API Gamma Ray LEFT [MWD]

150

API Gamma Ray RIGHT [MWD]

150

0

200

API Rate of Penetration

250

150

: : : 9950.00 - 13190.00 feet UP : 01/12/2005 04:57:54

MD feet 1:500

0

REALTIME IMAGE LOG

0

ft/hr

TCDX

10000

10050

0.2

Resistivity [PD] [LS] 2MHz [MWD]

2000

0.2

Ohm.m Resistivity [AT] [LS] 400 kHz [MWD]

2000

Ohm.m

0

Azimuthal Gamma Image

150

10100

10150

10200

10250

10300

10350

10400

10450

10500

10550

Company Well Field Rig County State Country

GAMMA RAY RESISTIVITY BULK DENSITY

Log as of:

NEUTRON POROSITY

Offshore North Sea United Kingdom

REALTIME LOG

1:500 Baker Hughes INTEQ does not guarantee the accuracy or correctness of interpretations provided in or from this log. Since all interpretations are opinions based on measurements, Baker Hughes INTEQ shall under no circumstances be held responsible for consequential damages or any other loss, costs, damages or expenses incurred or sustained in connection with the use of any such interpretations. Baker Hughes INTEQ disclaims all expressed and implied warranties related to its service which is governed by Baker Hughes INTEQ's standard terms and conditions.

Company : Well : Interval : 7250.00 - 13190.00 feet UP Created : 01/12/2005 04:57:54 degF Rate of Penetration

200

0

250

0

ft/hr Gamma Ray App [MWD]

150

MD feet 1:500

CDS Temperature [MWD]

GRIX

0

0.2

Resistivity [PD] [LS] 2MHz [MWD]

0.2

Ohm.m Resistivity [AT] [LS] 400 kHz [MWD] Ohm.m

2000

2000

1.95

45

Bulk Density Compensated (MWD)

2.95

g/cc Neutron Porosity (LS) (MWD)

-15

pu -0.25 Delta RHO (MWD) 0.25

API

g/cc

7300 RPCHX

7350

RACLX

GRAX

ROP 7400

> Run 1

TCDX

9900

9950

ABDCLX BDCX

GR1AX

10000

GRADX

10050

10100

10150

10200

10250

10300

10350

GAMMA RAY RESISTIVITY

Company Well

Offshore

DENSITY

Field

Southern North Sea

Rig

United Kingdom

NEUTRON POROSITY REALTIME LOG

County State Country

1:500 MEASURED DEPTH 15:00 18/08/05 Log as of:

Baker Hughes INTEQ does not guarantee the accuracy or correctness of interpretations provided in or from this log. Since all interpretations are opinions based on measurements, Baker Hughes INTEQ shall under no circumstances be held responsible for consequential damages or any other loss, costs, damages or expenses incurred or sustained in connection with the use of any such interpretations. Baker Hughes INTEQ disclaims all expressed and implied warranties related to its service which is governed by Baker Hughes INTEQ's standard terms and conditions.

Company : Well : Interval.19 feet UP Created : 18/Aug/2005 3:30:12 PM

0

API Rate of Penetration ft/hr CDS Temperature [MWD]

150

0

MD feet 1:500

100

Gamma Ray App [MWD]

GRIX

0

250

0.2

Resistivity [AT] [LS] 400 kHz [MWD]

2000 1.95

Bulk Density Compensated Down (MWD)

2.95

0.2

Ohm.m Resistivity [PD] [LS] 2MHz [MWD]

2000 1.95

g/cc Bulk Density Compensated Left (MWD)

2.95

1.95

g/cc Bulk Density Compensated Right (MWD)

2.95

1.95

g/cc Bulk Density Compensated Up (MWD)

2.95

1.95

g/cc Bulk Density Compensated (MWD)

2.95

g/cc Neutron [NPLX]

-15

Ohm.m

degF

45

pu -0.25 Delta RHO (MWD) 0.25 g/cc

11600

11650

11700

11750

11800

11850

11900

11950

12000

12050

12100

Ops & WSG Manual

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